Energen (EGN) 10-K 3 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information Document (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 14, 2014	Jun. 30, 2013
Entity Information [Line Items]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
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	'	72,713,965	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Public Float	'	'	$3,809,442,960
Alabama Gas Corporation	'	'	'
Entity Information [Line Items]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
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_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Revenues	'	'	'
Total operating revenues	$1,738,650	$1,540,819	$1,373,113
Operating Expenses	'	'	'
Cost of gas	215,455	142,228	233,523
Operations and maintenance	562,350	458,084	398,084
Depreciation, depletion and amortization	497,381	385,453	253,757
Asset impairment	29,794	21,545	0
Taxes, other than income taxes	105,268	86,801	88,351
Accretion expense	6,995	6,339	5,699
Total operating expenses	1,387,449	1,078,905	979,414
Income taxes	'	'	'
Operating Income	351,201	461,914	393,699
Other Income (Expense)	'	'	'
Interest expense	69,200	65,542	44,822
Other income	16,803	4,285	2,206
Other expense	-375	-903	-456
Total other income (expense)	-52,772	-62,160	-43,072
Interest Expense	'	'	'
Income From Continuing Operations Before Income Taxes	298,429	399,754	350,627
Income tax expense from continuing operations	105,282	144,534	126,322
Income From Continuing Operations	193,147	255,220	224,305
Income (loss) from discontinued operations	7,813	-1,658	35,319
Gain on disposal of discontinued operations, net	3,594	0	0
Total Income (Loss) From Discontinued Operations	11,407	-1,658	35,319
Net Income	204,554	253,562	259,624
Diluted Earnings Per Average Common Share	'	'	'
Continuing operations (in dollars per share)	$2.67	$3.53	$3.10
Discontinued operations (in dollars per share)	$0.15	($0.02)	$0.49
Net Income (in dollars per share)	$2.82	$3.51	$3.59
Basic Earnings Per Average Common Share	'	'	'
Continuing operations (in dollars per share)	$2.67	$3.54	$3.11
Discontinued operations (in dollars per share)	$0.16	($0.02)	$0.49
Net Income (in dollars per share)	$2.83	$3.52	$3.60
Dividends Per Common Share (dollars per share)	$0.58	$0.56	$0.54
Diluted Average Common Shares Outstanding	72,470,622	72,316,214	72,332,369
Basic Average Common Shares Outstanding	72,317,865	72,119,021	72,055,661
Alabama Gas Corporation	'	'	'
Operating Revenues	'	'	'
Natural gas distribution	533,338	451,589	534,953
Operating Expenses	'	'	'
Cost of gas	215,455	142,228	233,523
Operations and maintenance	143,138	141,334	139,030
Depreciation, depletion and amortization	43,907	42,270	39,916
Taxes, other than income taxes	37,070	32,541	36,268
Total operating expenses	474,257	388,617	475,407
Income taxes	'	'	'
Current	19,687	18,966	-1,388
Deferred	15,000	11,278	28,058
Operating Income	59,081	62,972	59,546
Other Income (Expense)	'	'	'
Interest expense	15,649	16,284	14,740
Allowance for funds used during construction	698	623	807
Other income	14,393	2,382	1,309
Other expense	-1,124	-291	-320
Total other income (expense)	13,967	2,714	1,796
Interest Expense	'	'	'
Interest on long-term debt	13,509	13,744	12,100
Other interest expense	2,140	2,540	2,640
Income tax expense from continuing operations	34,687	30,244	26,670
Net Income	$57,399	$49,402	$46,602

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net Income	$204,554	$253,562	$259,624
Cash flow hedges:	'	'	'
Total cash flow hedges	-32,018	35,864	51,999
Pension and postretirement plans:	'	'	'
Amortization of net obligation at transition, net of taxes of $112, $100 and $96, respectively	207	186	177
Amortization of prior service cost, net of taxes of $90, $119 and $104, respectively	167	221	194
Amortization of net loss, net of taxes of $4,472, $1,676 and $1,270, respectively	8,306	3,113	2,359
Current period change in fair value of pension and postretirement plans, net of taxes of $6,237, ($9,393), and ($5,699), respectively	11,582	-17,443	-10,584
Total pension and postretirement plans	20,262	-13,923	-7,854
Comprehensive Income	192,798	275,503	303,769
Commodity Contract	'	'	'
Cash flow hedges:	'	'	'
Reclassification adjustment for derivative instruments, net of tax	-10,866	66,438	67,547
Reclassification adjustment for derivative instruments, net of tax	-22,124	-29,359	-14,607
Interest Rate Swap	'	'	'
Cash flow hedges:	'	'	'
Reclassification adjustment for derivative instruments, net of tax	-148	-2,281	-941
Reclassification adjustment for derivative instruments, net of tax	$1,120	$1,066	$0

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Amortization of net obligation at transition, tax	$112	$100	$96
Amortization of prior service cost, tax	90	119	104
Amortization of net loss, tax	4,472	1,676	1,270
Current period change in fair value of pension and postretirement plans, tax	6,237	-9,393	-5,699
Commodity Contract	'	'	'
Reclassification adjustment for derivative instruments, tax	-13,560	-17,994	-8,953
Current period change in fair value of interest rate swap, tax	-6,660	40,720	41,399
Interest Rate Swap	'	'	'
Reclassification adjustment for derivative instruments, tax	-603	-574	0
Current period change in fair value of interest rate swap, tax	($80)	($1,228)	($507)

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current Assets	'	'
Cash and cash equivalents	$5,555	$9,704
Accounts receivable	'	'
Allowance for doubtful accounts	-5,694	-6,549
Accounts receivable, net of allowance for doubtful accounts of $5,694 and $6,549 at December 31, 2013 and 2012, respectively	257,545	277,900
Inventories	'	'
Storage gas inventory	32,095	32,205
Materials and supplies	16,601	28,291
Liquified natural gas in storage	3,634	3,498
Regulatory assets	2,756	45,515
Income tax receivable	5,765	6,664
Assets held for sale	51,104	0
Deferred income taxes	41,299	8,520
Prepayments and other	10,877	12,823
Total current assets	427,231	425,120
Property, Plant and Equipment	'	'
Oil and gas properties, successful efforts method	6,864,375	6,439,127
Less accumulated depreciation, depletion and amortization	1,776,802	1,765,241
Oil and gas properties, net	5,087,573	4,673,886
Utility plant	1,491,433	1,416,590
Less accumulated depreciation	605,924	573,947
Utility plant, net	885,509	842,643
Other property, net	30,556	25,107
Total property, plant and equipment, net	6,003,638	5,541,636
Other Assets	'	'
Regulatory assets	84,890	110,566
Other postretirement assets	35,351	1,404
Long-term derivative instruments	5,439	40,577
Deferred charges and other	65,663	56,587
Total other assets	191,343	209,134
TOTAL ASSETS	6,622,212	6,175,890
Current Liabilities	'	'
Long-term debt due within one year	60,000	50,000
Notes payable to banks	539,000	643,000
Accounts payable	250,756	257,579
Accrued taxes	36,228	30,076
Customer deposits	21,692	24,705
Amounts due customers	16,990	19,718
Accrued wages and benefits	33,884	24,984
Regulatory liabilities	49,006	45,116
Royalty payable	51,519	34,426
Liabilities related to assets held for sale	18,545	0
Other	32,273	30,178
Total current liabilities	1,109,893	1,159,782
Long-term debt	1,343,464	1,103,528
Deferred Credits and Other Liabilities	'	'
Asset retirement obligation	108,533	118,023
Pension liabilities	67,675	110,282
Regulatory liabilities	94,125	80,404
Deferred income taxes	1,013,245	905,601
Long-term derivative instruments	398	11,305
Other	26,860	10,275
Total deferred credits and other liabilities	1,310,836	1,235,890
Commitments and Contingencies	'	'
Shareholders' Equity	'	'
Preferred stock, cumulative, $0.01 par value	0	0
Common shareholders’ equity	'	'
Common stock, $0.01 par value	756	751
Premium on capital stock	520,909	492,108
Capital surplus	2,802	2,802
Retained earnings	2,476,616	2,314,055
Accumulated other comprehensive income (loss), net of tax	'	'
Unrealized gain on hedges, net	13,362	46,352
Pension and postretirement plans	-32,245	-52,507
Interest rate swap	-1,184	-2,156
Deferred compensation plan	3,259	2,774
Treasury stock, at cost: 2,967,999 shares and 2,998,620 shares at December 31, 2013 and 2012, respectively	-126,256	-127,489
Total shareholders’ equity	2,858,019	2,676,690
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	6,622,212	6,175,890
Alabama Gas Corporation	'	'
Current Assets	'	'
Cash and cash equivalents	3,032	5,559
Accounts receivable	'	'
Gas	103,301	94,011
Other	5,447	5,117
Affiliated companies	4,662	5,742
Allowance for doubtful accounts	-5,000	-5,700
Inventories	'	'
Storage gas inventory	32,095	32,205
Materials and supplies	5,471	5,528
Liquified natural gas in storage	3,634	3,498
Regulatory assets	2,756	45,515
Income tax receivable	3,644	2,762
Deferred income taxes	20,049	18,799
Prepayments and other	4,654	4,451
Total current assets	183,745	217,487
Property, Plant and Equipment	'	'
Utility plant	1,491,433	1,416,590
Less accumulated depreciation	605,924	573,947
Utility plant, net	885,509	842,643
Other property, net	41	42
Other Assets	'	'
Regulatory assets	84,890	110,566
Other postretirement assets	26,457	848
Deferred charges and other	17,433	11,290
Total other assets	128,780	122,704
TOTAL ASSETS	1,198,075	1,182,876
Current Liabilities	'	'
Notes payable to banks	50,000	77,000
Accounts payable	48,653	51,741
Accrued taxes	28,027	24,186
Customer deposits	21,692	24,705
Amounts due customers	16,990	19,718
Accrued wages and benefits	7,682	6,703
Regulatory liabilities	49,006	45,116
Other	10,113	9,018
Total current liabilities	232,163	258,187
Long-term debt	249,923	250,028
Deferred Credits and Other Liabilities	'	'
Pension liabilities	20,191	43,611
Regulatory liabilities	94,125	80,404
Deferred income taxes	205,631	189,381
Other	11,462	762
Total deferred credits and other liabilities	331,409	314,158
Commitments and Contingencies	'	'
Shareholders' Equity	'	'
Preferred stock, cumulative, $0.01 par value	0	0
Common shareholders’ equity	'	'
Common stock, $0.01 par value	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	350,076	325,999
Accumulated other comprehensive income (loss), net of tax	'	'
Total shareholders’ equity	384,580	360,503
Total capitalization	634,503	610,531
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$1,198,075	$1,182,876

CONSOLIDATED_BALANCE_SHEETS_Co

CONSOLIDATED BALANCE SHEETS Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Allowance for doubtful accounts	$5,694	$6,549
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	75,574,156	75,067,760
Treasury stock, shares	2,967,999	2,998,620
Alabama Gas Corporation	'	'
Allowance for doubtful accounts	$5,000	$5,700
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_STATEMENTS_OF_SHA

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (USD $)

Total

Common Stock

Premium on Capital Stock

Capital Surplus

Retained Earnings

Accumulated Other Comprehensive Income (Loss)

Deferred Compensation Plan

Treasury Stock

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

In Thousands, except Share data, unless otherwise specified

Common Stock

Premium on Capital Stock

Capital Surplus

Retained Earnings

BALANCE at Dec. 31, 2010

$2,154,043

$748

$468,934

$2,802

$1,880,183

($74,397)

$3,288

($127,515)

$327,319

$20

$31,682

$2,802

$292,815

BALANCE, shares at Dec. 31, 2010

'

74,786,376

'

'

'

'

'

'

'

1,972,052

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

259,624

'

'

'

259,624

'

'

'

46,602

'

'

'

46,602

Other comprehensive income

44,145

'

'

'

'

44,145

'

'

'

'

'

'

'

Purchase of treasury shares, net

-713

'

'

'

'

'

'

-713

'

'

'

'

'

Shares issued for employee benefit plans, shares

'

221,036

'

'

'

'

'

'

'

'

'

'

'

Shares issued for employee benefit plans

7,237

2

7,235

'

'

'

'

'

'

'

'

'

'

Deferred compensation obligation

0

'

'

'

'

'

223

-223

'

'

'

'

'

Stock-based compensation

5,763

'

5,763

'

'

'

'

'

'

'

'

'

'

Tax benefit from employee stock plans

986

'

986

'

'

'

'

'

'

'

'

'

'

Cash dividends, per share - ($0.54 in 2011, $0.56 in 2012, $0.58 in 2013)

-38,922

'

'

'

-38,922

'

'

'

-29,183

'

'

'

-29,183

BALANCE at Dec. 31, 2011

2,432,163

750

482,918

2,802

2,100,885

-30,252

3,511

-128,451

344,738

20

31,682

2,802

310,234

BALANCE, shares at Dec. 31, 2011

'

75,007,412

'

'

'

'

'

'

'

1,972,052

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

57,406

'

'

'

'

'

'

'

46,918

'

'

'

'

BALANCE at Mar. 31, 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

BALANCE at Dec. 31, 2011

2,432,163

750

482,918

2,802

2,100,885

-30,252

3,511

-128,451

344,738

20

31,682

2,802

310,234

BALANCE, shares at Dec. 31, 2011

'

75,007,412

'

'

'

'

'

'

'

1,972,052

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

253,562

'

'

'

253,562

'

'

'

49,402

'

'

'

49,402

Other comprehensive income

21,941

'

'

'

'

21,941

'

'

'

'

'

'

'

Purchase of treasury shares, net

-277

'

'

'

'

'

'

-277

'

'

'

'

'

Shares issued for employee benefit plans, shares

'

60,348

'

'

'

'

'

'

'

'

'

'

'

Shares issued for employee benefit plans

2,061

1

2,060

'

'

'

'

'

'

'

'

'

'

Deferred compensation obligation

0

'

'

'

'

'

-737

737

'

'

'

'

'

Stock-based compensation

7,082

'

6,580

'

'

'

'

502

'

'

'

'

'

Tax benefit from employee stock plans

550

'

550

'

'

'

'

'

'

'

'

'

'

Cash dividends, per share - ($0.54 in 2011, $0.56 in 2012, $0.58 in 2013)

-40,392

'

'

'

-40,392

'

'

'

-33,637

'

'

'

-33,637

BALANCE at Dec. 31, 2012

2,676,690

751

492,108

2,802

2,314,055

-8,311

2,774

-127,489

360,503

20

31,682

2,802

325,999

BALANCE, shares at Dec. 31, 2012

75,067,760

75,067,760

'

'

'

'

'

'

1,972,052

1,972,052

'

'

'

BALANCE at Sep. 30, 2012

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

62,823

'

'

'

'

'

'

'

12,197

'

'

'

'

BALANCE at Dec. 31, 2012

2,676,690

'

'

2,802

'

'

'

'

360,503

20

31,682

2,802

'

BALANCE, shares at Dec. 31, 2012

75,067,760

'

'

'

'

'

'

'

1,972,052

1,972,052

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

56,692

'

'

'

'

'

'

'

47,222

'

'

'

'

BALANCE at Mar. 31, 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

BALANCE at Dec. 31, 2012

2,676,690

751

492,108

2,802

2,314,055

-8,311

2,774

-127,489

360,503

20

31,682

2,802

325,999

BALANCE, shares at Dec. 31, 2012

75,067,760

75,067,760

'

'

'

'

'

'

1,972,052

1,972,052

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

204,554

'

'

'

204,554

'

'

'

57,399

'

'

'

57,399

Other comprehensive income

-11,756

'

'

'

'

-11,756

'

'

'

'

'

'

'

Purchase of treasury shares, net

-1,038

'

'

'

'

'

'

-1,038

'

'

'

'

'

Shares issued for employee benefit plans, shares

'

506,396

'

'

'

'

'

'

'

'

'

'

'

Shares issued for employee benefit plans

18,795

5

18,790

'

'

'

'

'

'

'

'

'

'

Deferred compensation obligation

0

'

'

'

'

'

485

-485

'

'

'

'

'

Stock-based compensation

9,625

'

6,869

'

'

'

'

2,756

'

'

'

'

'

Tax benefit from employee stock plans

3,142

'

3,142

'

'

'

'

'

'

'

'

'

'

Cash dividends, per share - ($0.54 in 2011, $0.56 in 2012, $0.58 in 2013)

-41,993

'

'

'

-41,993

'

'

'

-33,322

'

'

'

-33,322

BALANCE at Dec. 31, 2013

2,858,019

756

520,909

2,802

2,476,616

-20,067

3,259

-126,256

384,580

20

31,682

2,802

350,076

BALANCE, shares at Dec. 31, 2013

75,574,156

75,574,156

'

'

'

'

'

'

1,972,052

1,972,052

'

'

'

BALANCE at Sep. 30, 2013

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Income

84,093

'

'

'

'

'

'

'

19,842

'

'

'

'

BALANCE at Dec. 31, 2013

$2,858,019

'

'

$2,802

'

'

'

'

$384,580

$20

$31,682

$2,802

'

BALANCE, shares at Dec. 31, 2013

75,574,156

'

'

'

'

'

'

'

1,972,052

1,972,052

'

'

'

CONSOLIDATED_STATEMENTS_OF_SHA1

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY Consolidated Statements of Shareholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Stockholders' Equity [Abstract]	'	'	'
Common Stock, Dividends, Per Share, Cash Paid	$0.58	$0.56	$0.54

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Activities	'	'	'
Net Income	$204,554	$253,562	$259,624
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation and amortization	497,381	385,453	253,757
Depreciation, depletion and amortization	527,845	419,598	283,997
Asset impairment	29,794	21,545	0
Accretion expense	8,192	7,534	6,837
Deferred income taxes	83,650	124,399	129,041
Bad debt expense	781	153	2,525
Change in derivative fair value	48,029	-41,819	36,210
Gain on sale of assets	-46,377	-529	-5,994
Stock-based compensation expense	14,892	6,047	9,011
Exploratory expense	16,008	16,757	10,916
Other, net	23,810	8,597	7,537
Net change in:	'	'	'
Accounts receivable	4,216	-11,923	-16,359
Inventories	11,596	10,018	-14,710
Accounts payable	-58,859	-16,392	12,978
Amounts due customers, including gas supply pass-through	40,542	-57,747	-2,597
Income tax receivable	899	679	37,146
Pension and other postretirement benefit contributions	-11,747	-5,996	-5,986
Other current assets and liabilities	29,552	1,254	11,655
Net cash provided by operating activities	927,377	735,737	761,831
Investing Activities	'	'	'
Additions to property, plant and equipment	-1,195,402	-1,184,300	-889,614
Acquisitions, net of cash acquired	-31,331	-139,563	-310,193
Proceeds from sale of assets	174,824	2,562	7,987
Purchase of short-term investments	-310,000	0	0
Sale of short-term investments	310,000	0	0
Other, net	-1,701	-881	-1,679
Net cash used in investing activities	-1,053,610	-1,322,182	-1,193,499
Financing Activities	'	'	'
Payment of dividends on common stock	-41,993	-40,392	-38,922
Issuance of common stock	17,780	1,224	6,415
Issuance of long-term debt	600,000	0	749,952
Reduction of long-term debt	-350,105	-1,218	-5,547
Net change in short-term debt	-104,000	628,000	-290,000
Tax benefit on stock compensation	3,142	550	986
Other	-2,740	-1,556	-4,334
Net cash provided by financing activities	122,084	586,608	418,550
Net change in cash and cash equivalents	-4,149	163	-13,118
Cash and cash equivalents at beginning of period	9,704	9,541	22,659
Cash and cash equivalents at end of period	5,555	9,704	9,541
Alabama Gas Corporation	'	'	'
Operating Activities	'	'	'
Net Income	57,399	49,402	46,602
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation and amortization	43,907	42,270	39,916
Deferred income taxes	15,000	11,278	28,058
Bad debt expense	774	146	2,457
Gain on sale of assets	-10,889	0	0
Other, net	14,068	10,667	1,560
Net change in:	'	'	'
Accounts receivable	-23,955	-13,528	4,862
Inventories	31	10,544	-7,371
Accounts payable	-2,464	-5,906	-1,499
Amounts due customers, including gas supply pass-through	40,542	-57,747	-2,597
Income tax receivable	-882	7,000	553
Pension and other postretirement benefit contributions	-6,070	-2,725	-2,811
Other current assets and liabilities	2,700	-8,654	-2,802
Net cash provided by operating activities	130,161	42,747	106,928
Investing Activities	'	'	'
Additions to property, plant and equipment	-86,037	-69,860	-73,447
Proceeds from sale of assets	13,838	0	0
Other, net	-62	-3,252	-2,743
Net cash used in investing activities	-72,261	-73,112	-76,190
Financing Activities	'	'	'
Payment of dividends on common stock	-33,322	-33,637	-29,183
Issuance of long-term debt	0	0	50,000
Reduction of long-term debt	-105	-218	-5,547
Net change in short-term debt	-27,000	62,000	-55,000
Other	0	-38	-101
Net cash provided by financing activities	-60,427	28,107	-39,831
Net change in cash and cash equivalents	-2,527	-2,258	-9,093
Cash and cash equivalents at beginning of period	5,559	7,817	16,910
Cash and cash equivalents at end of period	$3,032	$5,559	$7,817

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Summary of Significant Accounting Policies	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Energen Corporation (Energen or the Company) is an oil and gas exploration and production company complemented by its legacy natural gas distribution business. Headquartered in Birmingham, Alabama, the Company is engaged in the development, exploration and production of oil and gas in the continental United States (oil and gas operations) and in the purchase, distribution and sale of natural gas principally in central and north Alabama (natural gas distribution). The following is a description of the Company’s significant accounting policies and practices.
	A. Principles of Consolidation
	The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation (Alagasco), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years’ financial statements to the current-year presentation.
	B. Oil and Gas Operations
	Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.
	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 during the year:
	Years ended December 31, (in thousands)	2013			2012			2011
	Capitalized exploratory well costs at beginning of period	$	79,791		$	70,437		$	21,438
	Additions pending determination of proved reserves	421,599			406,226			178,005
	Reclassifications due to determination of proved reserves	(442,909		)	(396,872		)	(129,006		)
	Exploratory well costs charged to expense	(881		)	—			—
	Capitalized exploratory well costs at end of period	$	57,600		$	79,791		$	70,437
	The following table sets forth capitalized exploratory wells costs at year end and includes amounts capitalized for a period greater than one year:
	Years ended December 31, (in thousands)	2013			2012			2011
	Exploratory wells in progress	$	14,794		$	77,693		$	70,437
	Capitalized exploratory well costs for a period of one year or less	42,481			—			—
	Capitalized exploratory well costs for a period greater than one year	1,206			2,098			—
	Total capitalized exploratory well costs	$	58,481		$	79,791		$	70,437
	At December 31, 2013, the Company had 48 gross exploratory wells either drilling or waiting on results from completion and testing. All of these wells are 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.
	Operating Revenues: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no significant production imbalances at December 31, 2013 and 2012.
	Derivative Commodity Instruments: Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows.
	The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of December 31, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights which may be exercised by the non-defaulting party in the event of an early termination due to a default.
	Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. The effective portion of the gain or loss on the derivative instrument was recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value 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 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. 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.
	Open mark-to-market gains (losses) on derivatives included in operating revenues were as follows:
	Years ended December 31, (in thousands)	2013			2012			2011
	Mark-to-market gain (loss) on derivatives	$	(47,832	)	$	58,750		$	(37,587	)
	All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged.
	Long-Lived Assets and Discontinued Operations: The Company reports gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for certain held-for-sale properties are reclassified and reported as discontinued operations for prior periods. 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.
	Acquisitions: Energen Resources recognizes all acquisitions at fair value. Energen Resources estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen Resources obtained control of the properties for all acquisitions that qualify as business combinations. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. Energen Resources uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in operations and maintenance (O&M) expense on the consolidated income statements.
	C. Natural Gas Distribution
	Regulatory Accounting: Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) with respect to rates, accounting and various other matters. Alagasco capitalizes or defers certain costs or revenues, based on the approvals received from the APSC, to be recovered from or refunded to customers in future periods. These costs or revenues are recorded as regulatory assets or liabilities.
	Utility Plant and Depreciation: Property, plant and equipment are stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. Gains and losses on all dispositions of land are recognized at time of disposal. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets are charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the APSC. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $16.3 million, $14.2 million, $22.2 million and $2.7 million for the years ended December 31, 2013, 2012 and 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $15.8 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $39.7 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a five year period beginning January 1, 2015. The total amount refundable to customers is subject to adjustments over the remaining five year period for charges made to the Enhanced Stability Reserve (ESR) and other APSC approved charges. The refunds as of December 2013 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates. Approved depreciation rates averaged approximately 3.1 percent, 3.2 percent and 3.1 percent in the years ended December 31, 2013, 2012 and 2011, respectively.
	Inventories: Inventories, which consist primarily of gas stored underground, are stated at average cost. Liquified natural gas is stated at base cost.
	Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2013 and 2012.
	Derivative Commodity Instruments: In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Alagasco.
	Taxes on Revenues: The collection and payment of revenue taxes such as utility license taxes and fees, franchise fees and taxes imposed by other governmental authorities are reported on a gross basis. These amounts are included in taxes, other than income taxes on the consolidated statements of income as follows:
	Years ended December 31, (in thousands)	2013			2012			2011
	Taxes on revenues	$	25,870		$	21,479		$	25,268
	The collection and payment of utility gross receipts tax is presented on a net basis.
	D. Fair Value Measurements
	The carrying values of cash and cash equivalents, accounts payable and receivable, derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The fair value hierarchy that prioritizes the inputs used to measure fair value is defined as follows:
	Level 1 -	Unadjusted quoted prices in active markets for identical assets or liabilities;
	Level 2 -	Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;
	Level 3 -	Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.
	Derivative commodity instruments are OTC derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties’ valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.
	Pension and postretirement plan assets include mutual and comingled funds and limited partnerships. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds. Level 3 fair values used unobservable market prices primarily associated with certain alternative investments and a limited partnership.
	E. Income Taxes
	The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.
	F. Accounts Receivable and Allowance for Doubtful Accounts
	Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The Company determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.
	G. Cash and Cash Equivalents
	Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.
	H. Short-term Investments
	All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. As of December 31, 2013 and 2012, Energen had no short-term investments.
	I. Earnings Per Share (EPS)
	The Company’s basic earnings per share amounts have been computed based on the weighted average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities.
	J. Stock-Based Compensation
	The Company measures all share-based compensation awards at fair value at the date of grant and expenses the awards over the requisite vesting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. The Company recognizes all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. The Company utilizes the long-form method of calculating the available pool of windfall tax benefit. For the years ended December 31, 2013, 2012 and 2011, the Company recognized an excess tax benefit of $3.1 million, $0.6 million and $1.0 million, respectively, related to its stock-based compensation.
	K. Estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that regulatory accounting will continue as the applicable accounting standard for the Company’s regulated operations, the Company’s obligations under its employee pension and compensation plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves, asset retirement obligations, self insurance reserves and regulatory assets and liabilities. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.
L. Employee Benefit Plans
Energen has two defined benefit non-contributory qualified pension plans. These plans cover substantially all employees. Pension benefits for the majority of the Company’s employees are based on years of service and final earnings; one plan is based on years of service and flat dollar amounts. The Company also has nonqualified supplemental pension plans covering certain officers of the Company. In addition to providing pension benefits, the Company provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. The Company continues to provide these benefits to certain non-salaried employees. These postretirement healthcare and life insurance benefits are available upon reaching normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.
For retirement plans and other postretirement plans, certain financial assumptions are used in determining the Company’s projected benefit obligation. These assumptions are examined periodically by the Company, and any required changes are reflected in the subsequent determination of projected benefit obligations.
Measurement: The Company calculates periodic expense for defined benefit pension plans and other postretirement benefit plans on an actuarial basis and the net funded status of benefit plans is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligation to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be provided through rates in the future. The Company measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.
Discount Rate: In selecting each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate for each plan was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments.
Long-Term Rate of Return: The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The Company considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets.
Other Significant Assumptions: The estimated weighted average rate of increase in the compensation level for pay related plans is another assumption used in calculation of the net periodic pension cost.
M. Environmental Costs
Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated. As more fully described in Note 2, Regulatory Matters, and as currently approved, the ESR provides deferred treatment and recovery for extraordinary O&M expenses related to environmental response costs.

Regulatory_Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2013
Regulated Operations [Abstract]	'
Regulatory Matters	'
	REGULATORY MATTERS
	Alagasco is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s RSE order had an original term extending through December 31, 2014. On December 20, 2013, the APSC issued a final written order modifying RSE effective January 1, 2014 as follows. The term of the order is extended through September 30, 2018. The term 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. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to O&M expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from 2007 actual expenses, adjusted for inflation using the Index Range.  Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for Securities and Exchange Commission reporting purposes.
	Alagasco’s allowed range of return on average common equity is 13.15 percent to 13.65 percent through December 31, 2013. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the years ended December 31, 2013, 2012 and 2011, Alagasco had net pre-tax reductions in revenues of $10.6 million, $6.3 million and $6.7 million, respectively, to bring the return on average equity to midpoint within the allowed range of return. Under the provisions of RSE, a $10.3 million annual increase, $7.8 million annual increase and $13.0 million annual increase in revenues became effective December 1, 2013, 2012, and 2011, respectively. On January 1, 2014 an $8.5 million decrease in revenues became effective as a result of the December 20, 2013 RSE modification.
	RSE limits the utility’s equity upon which a return was permitted to 55 percent of total capitalization, subject to certain adjustments through December 31, 2013. Currently, under the inflation-based CCM established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the September Index Range on a rate year basis, no adjustment was required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference was returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless Alagasco exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2013, 2012 and 2011.
	Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.
	The APSC approved an Enhanced Stability Reserve in 1998 which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year.
	Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $660,000. Amounts in excess of this limitation are deferred for recovery in future years.
	The excess of total acquisition costs over book value of net assets of acquired municipal gas distribution systems is included in utility plant and is being amortized through Alagasco’s rate-setting mechanism on a straight-line basis with a weighted average remaining life of approximately 13 years. At December 31, 2013 and 2012, the net unamortized acquisition adjustments were $3.2 million and $3.8 million, respectively.

LongTerm_Debt_and_Notes_Payabl

Long-Term Debt and Notes Payable	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt and Notes Payable	'
	LONG-TERM DEBT AND NOTES PAYABLE
	Long-term debt consisted of the following:
	(in thousands)	December 31, 2013			December 31, 2012
	Energen Corporation:
	Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 24, 2017 to February 15, 2028	$	154,000		$	154,000
	5% Notes	—			50,000
	4.625% Notes, due September 1, 2021	400,000			400,000
	Senior Term Loans, (floating rate interest LIBOR plus 1.625%; 1.792% at December 31, 2013), due March 31, 2014 to December 17, 2017	600,000			—
	Senior Term Loans, (floating rate interest LIBOR plus 1.375%)	—			300,000
	Alabama Gas Corporation:
	5.20% Notes, due January 15, 2020	40,000			40,000
	5.70% Notes, due January 15, 2035	34,923			35,028
	5.368% Notes, due December 1, 2015	80,000			80,000
	5.90% Notes, due January 15, 2037	45,000			45,000
	3.86% Notes, due December 21, 2021	50,000			50,000
	Total	1,403,923			1,154,028
	Less amounts due within one year	60,000			50,000
	Less unamortized debt discount	459			500
	Total	$	1,343,464		$	1,103,528
	The aggregate maturities of Energen’s long-term debt for the next five years are as follows:
	Years ending December 31, (in thousands)
	2014	2015	2016	2017	2018
	$60,000	$140,000	$60,000	$439,000	—
	The aggregate maturities of Alagasco’s long-term debt for the next five years are as follows:
	Years ending December 31, (in thousands)
	2014	2015	2016	2017	2018
	—	$80,000	—	—	—
	In December 2013, the Company issued $600 million in Senior Term Loans (Senior Term Loans) with a floating interest rate due March 31, 2014 through December 17, 2017. The Company used the long-term debt proceeds to repay the Senior Term Loans of $300 million issued in November 2011 and to repay short-term obligations under its syndicated credit facility.
	At December 31, 2013, 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 $1.8 million and a $3.3 million liability at December 31, 2013 and 2012, respectively, and is classified as a 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.
	The long-term debt and short-term debt agreements of Energen and Alagasco contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. Although none of the agreements have covenants or events of default based on credit ratings, the interest rates applicable to the Senior Term Loans and the Energen and Alagasco syndicated credit facilities discussed below may adjust based on credit rating changes. All of the Company’s debt is unsecured.
	Under Energen’s Indenture dated September 1, 1996 with The Bank of New York as Trustee, a cross default provision provides that any debt default of more than $10 million by Energen, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s Indenture dated November 1, 1993 with The Bank of New York as Trustee, a cross default provision provides that any debt default by Alagasco of more than $10 million will constitute an event of default by Alagasco. Neither Indenture includes a restriction on the payment of dividends.
	Energen and Alagasco Credit Facilities: On October 30, 2012, Energen and Alagasco entered into $1.25 billion and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. Borrowings under these credit facilities are subject to the execution of individual note agreements each with maturity dates of less than one year. Accordingly, outstanding amounts due under these credit facilities are classified as short term obligations in the accompanying consolidated financial statements. Alagasco has been authorized by the APSC to borrow up to $200 million at any one time under the short-term credit facilities.
	Energen’s obligations under the $1.25 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. The financial covenants of the Energen credit facility limit Energen to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Energen may not pay dividends during an event of default or if the payment would result in an event of default.
	Similarly, the financial covenants of the Alagasco credit facility limit Alagasco to a maximum consolidated debt to capitalization ratio of no more than 65 percent as of the end of any fiscal quarter. Alagasco may not pay dividends during an event of default or if the payment would result in an event of default.
	Under the Energen credit facility, a cross default provision provides that any debt default of more than $50 million by Energen, Alagasco or Energen Resources will constitute an event of default by Energen. Under Alagasco’s credit facility, a cross default provision provides that any debt default by Alagasco of more than $50 million will constitute an event of default by Alagasco.
	Upon an uncured event of default under either of the credit facilities, all amounts owing under the defaulted credit facility, if any, depending on the nature of the event of default will automatically, or may upon notice by the administrative agent or the requisite lenders thereunder, become immediately due and payable and the lenders may terminate their commitments under the defaulted facility. Energen and Alagasco were in compliance with the terms of their respective credit facilities as of December 31, 2013.
	The following is a summary of information relating to the credit facilities:
	(in thousands)	December 31, 2013			December 31, 2012
	Energen outstanding	$	489,000		$	566,000
	Alagasco outstanding	50,000			77,000
	Notes payable to banks	539,000			643,000
	Available for borrowings	811,000			707,000
	Total	$	1,350,000		$	1,350,000
	Energen maximum amount outstanding at any month-end	$	901,000		$	643,000
	Energen average daily amount outstanding	$	804,895		$	331,068
	Energen weighted average interest rates based on:
	Average daily amount outstanding	1.38		%	1.82		%
	Amount outstanding at year-end	1.32		%	1.35		%
	Alagasco maximum amount outstanding at any month-end	$	75,000		$	77,000
	Alagasco average daily amount outstanding	$	35,027		$	21,254
	Alagasco weighted average interest rates based on:
	Average daily amount outstanding	1.12		%	1.44		%
	Amount outstanding at year-end	1.26		%	1.11		%
	Energen’s total interest expense was $69.2 million, $65.5 million and $44.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. Energen’s total interest expense for the years ended December 31, 2013 and 2012 included capitalized interest expense of $0.2 million and $0.5 million. Total interest expense for Alagasco was $15.6 million, $16.3 million and $14.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. At December 31, 2013, Energen and Alagasco paid commitment fees on the unused portion of available credit facilities ranging from 15 to 25 basis points per annum.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	INCOME TAXES
	The components of Energen’s income taxes consisted of the following:
	Years ended December 31, (in thousands)	2013			2012			2011
	Taxes estimated to be payable currently:
	Federal	$	23,342		$	16,295		$	11,595
	State	2,516			3,125			5,065
	Total current	25,858			19,420			16,660
	Taxes deferred:
	Federal	85,950			119,053			125,622
	State	(2,300		)	5,346			3,419
	Total deferred	83,650			124,399			129,041
	Total income tax expense	$	109,508		$	143,819		$	145,701
	The components of Energen’s income taxes consisted of the following:
	Years ended December 31, (in thousands)	2013			2012			2011
	Income tax expense from continuing operations	$	105,282		$	144,534		$	126,322
	Income tax expense (benefit) from discontinued operations	2,215			(715		)	19,379
	Income tax expense from gain on disposal of discontinued operations	2,011			—			—
	Total income tax expense	$	109,508		$	143,819		$	145,701
	The components of Alagasco’s income taxes consisted of the following:
	Years ended December 31, (in thousands)	2013			2012			2011
	Taxes estimated to be payable currently:
	Federal	$	17,495		$	18,227		$	(1,280	)
	State	2,192			739			(108		)
	Total current	19,687			18,966			(1,388		)
	Taxes deferred:
	Federal	13,252			9,066			24,938
	State	1,748			2,212			3,120
	Total deferred	15,000			11,278			28,058
	Total income tax expense	$	34,687		$	30,244		$	26,670
	Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows:
	(in thousands)	December 31, 2013						December 31, 2012
		Current			Noncurrent			Current			Noncurrent
	Deferred tax assets:
	Unbilled and deferred revenue	$	12,547		$	—		$	10,137		$	—
	Allowance for doubtful accounts	2,066			—			2,408			—
	Insurance and other accruals	4,851			—			3,821			—
	Compensation accruals	15,405			—			13,116			—
	Inventories	1,260			—			1,664			—
	Other comprehensive income	—			15,350			—			19,158
	Gas supply adjustment related accruals	698			—			969			—
	Derivative instruments	10,769			—			—			—
	State net operating losses and other carryforwards	—			4,577			—			3,577
	Other	1,219			1			1,340			25
	Total deferred tax assets	48,815			19,928			33,455			22,760
	Valuation allowance	(299		)	(2,674		)	(268		)	(2,793		)
	Total deferred tax assets	48,516			17,254			33,187			19,967
	Deferred tax liabilities:
	Depreciation and basis differences	—			1,008,026			—			898,625
	Pension and other costs	—			15,379			—			20,143
	Derivative instruments	—			2,048			4,272			3,162
	Other comprehensive income	5,540			—			18,133			—
	Other	1,677			5,046			2,262			3,638
	Total deferred tax liabilities	7,217			1,030,499			24,667			925,568
	Net deferred tax assets (liabilities)	$	41,299		$	(1,013,245	)	$	8,520		$	(905,601	)
	Temporary differences and carryforwards which gave rise to Alagasco’s deferred tax assets and liabilities were as follows:
	(in thousands)	December 31, 2013						December 31, 2012
		Current			Noncurrent			Current			Noncurrent
	Deferred tax assets:
	Unbilled and deferred revenue	$	12,547		$	—		$	10,137		$	—
	Allowance for doubtful accounts	1,815			—			2,155			—
	Insurance accruals	1,769			—			1,856			—
	Compensation accruals	2,480			—			2,645			—
	Inventories	1,260			—			1,664			—
Gas supply adjustment related accruals	698			—			969			—
Other	984			1			774			2
Total deferred tax assets	21,553			1			20,200			2
Deferred tax liabilities:
Depreciation and basis differences	—			186,601			—			167,329
Pension and other costs	—			19,031			—			22,054
Other	1,504			—			1,401			—
Total deferred tax liabilities	1,504			205,632			1,401			189,383
Net deferred tax assets (liabilities)	$	20,049		$	(205,631	)	$	18,799		$	(189,381	)
The Company files a consolidated federal income tax return with all of its subsidiaries. The Company has a noncurrent deferred tax asset of $1.6 million relating to Energen Resources’ $35.0 million state net operating loss carryforward which will expire beginning in 2027. Energen Resources anticipates generating adequate future taxable income to fully realize this benefit. The Company has a full valuation allowance recorded against a noncurrent deferred tax asset of $3.0 million arising from certain state net operating loss and charitable contribution carryforwards. The Company intends to fully reserve this asset until it is determined that it is more likely than not that the asset can be realized through future taxable income in the respective state taxing jurisdictions. No other valuation allowance with respect to deferred taxes is deemed necessary as the Company anticipates generating adequate future taxable income to realize the benefits of all remaining deferred tax assets on the consolidated balance sheets.
In accordance with Accounting Standards Codification 740-30-25-7, the Company has not recognized a deferred tax liability for the difference between the book basis and the tax basis in the stock of its subsidiaries. The unrecorded gross outside basis difference for Alagasco exceeds the recorded inside asset basis difference by approximately $37.0 million and would result in an additional deferred tax liability of $14.0 million.
Total income tax expense from continuing operations for the Company differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:
Years ended December 31, (in thousands)	2013			2012			2011
Income tax expense at statutory federal income tax rate	$	104,450		$	139,914		$	122,719
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	3,799			4,755			8,341
Impact of state law changes	(1,966		)	—			(2,059		)
Qualified Section 199 production activities deduction	—			(61		)	(495		)
401(k) stock dividend deduction	(449		)	(514		)	(532		)
Other, net	(552		)	440			(1,652		)
Total income tax expense	$	105,282		$	144,534		$	126,322
Effective income tax rate (%)	35.28			36.16			36.03
Total income tax expense for Alagasco differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:
Years ended December 31, (in thousands)	2013			2012			2011
Income tax expense at statutory federal income tax rate	$	32,230		$	27,876		$	25,645
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	2,588			2,238			2,059
Reversal of tax reserves from audit settlements, net	—			—			(1,365		)
Other, net	(131		)	130			331
Total income tax expense	$	34,687		$	30,244		$	26,670
Effective income tax rate (%)	37.67			37.97			36.4
A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows:
(in thousands)
Balance as of December 31, 2010	$	24,590
Additions based on tax positions related to the current year	3,644
Additions for tax positions of prior years	2,324
Reductions for tax positions of prior years	(39		)
Lapse of statute of limitations	(1,482		)
Settlements	(18,444		)
Balance as of December 31, 2011	10,593
Additions based on tax positions related to the current year	3,731
Additions for tax positions of prior years	269
Reductions for tax positions of prior years	(446		)
Lapse of statute of limitations	(1,592		)
Balance as of December 31, 2012	12,555
Additions based on tax positions related to the current year	4,546
Additions for tax positions of prior years	366
Reductions for tax positions of prior years	(46		)
Lapse of statute of limitations	(1,435		)
Balance as of December 31, 2013	$	15,986
The reduction for settlements in 2011 are primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property that was in dispute under an Internal Revenue Service (IRS) examination of the Company’s 2007-2008 federal consolidated income tax returns. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco was allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns. The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.
During 2011, the Company had a gross addition of $5.9 million and recognized in its effective income tax rate $2.9 million of income tax expense for additional unrecognized tax benefit liabilities. These liabilities were partially offset by a $1.5 million benefit for the release of the unrecognized income tax benefit liability due to the Company’s settlement with the IRS discussed above.
The amount of unrecognized tax benefits at December 31, 2013 that would favorably impact the Company’s effective tax rate, if recognized, is $6.9 million. The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2013, 2012, and 2011, the Company recognized approximately $15,000 of expense, $25,000 of income and $1.4 million of income for interest (net of tax benefit) and penalties, respectively. The Company had approximately $0.2 million and $0.2 million for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2013 and 2012, respectively.
A reconciliation of Alagasco’s beginning and ending amount of unrecognized tax benefits is as follows:
(in thousands)
Balance as of December 31, 2010	$	18,941
Additions based on tax positions related to the current year	13
Additions for tax positions of prior years	1
Reductions for tax positions of prior years (lapse of statute of limitations)	(409		)
Settlements	(18,444		)
Balance as of December 31, 2011	102
Additions based on tax positions related to the current year	62
Additions for tax positions of prior years	201
Reductions for tax positions of prior years (lapse of statute of limitations)	(58		)
Balance as of December 31, 2012	307
Reductions for tax positions of prior years (lapse of statute of limitations)	(31		)
Balance as of December 31, 2013	$	276
The reduction for settlements in 2011 are primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property discussed above. None of Alagasco’s unrecognized tax benefits at December 31, 2013 would impact the Company’s effective tax rate, if recognized. Alagasco recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. During the years ended December 31, 2013, 2012, and 2011, Alagasco recognized approximately $4,000 of expense, $1,000 of income and $1.4 million of income for interest (net of tax benefit) and penalties, respectively. Alagasco had approximately $8,000 and $4,000 for the payment of interest (net of tax benefit) and penalties accrued at December 31, 2013 and 2012, respectively.
The Company and Alagasco’s tax returns for years 2010-2012 remain open and subject to examination by the IRS and major state taxing jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statement

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2013
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]	'
Employee Benefit Plans	'
	EMPLOYEE BENEFIT PLANS
	Benefit Obligations: The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in the Company’s consolidated financial statements:
	As of December 31, (in thousands)	2013				2012			2013				2012
		Pension							Postretirement Benefits
	Accumulated benefit obligation	$	253,030			$	269,101
	Benefit obligation:
	Balance at beginning of period	$	323,540			$	250,619		$	85,785			$	88,064
	Service cost	14,173				10,527			1,694				1,853
	Interest cost	11,239				10,801			3,504				4,248
	Actuarial (gain) loss	(28,339		)		65,048			(21,681		)		(5,413		)
	Curtailment gain	(4,223		)		—			(1,255		)		—
	Retiree drug subsidy program	—				—			261				360
	Benefits paid	(23,036		)		(13,455		)	(4,726		)		(3,327		)
	Balance at end of period	$	293,354			$	323,540		$	63,582			$	85,785
	Plan assets:
	Fair value of plan assets at beginning of period	$	209,424			$	195,659		$	87,189			$	78,121
	Actual return on plan assets	22,977				24,841			14,892				8,778
	Employer contributions	10,169				2,379			1,578				3,617
	Benefits paid	(23,036		)		(13,455		)	(4,726		)		(3,327		)
	Fair value of plan assets at end of period	$	219,534			$	209,424		$	98,933			$	87,189
	Funded status of plans	$	(73,820	)		$	(114,116	)	$	35,351			$	1,404
	Noncurrent assets	$	—			$	—		$	35,351			$	1,404
	Current liabilities	(6,145		)		(3,834		)	—				—
	Noncurrent liabilities	(67,675		)		(110,282		)	—				—
	Net asset (liability) recognized	$	(73,820	)		$	(114,116	)	$	35,351			$	1,404
	Amounts recognized to accumulated other comprehensive income:
	Prior service costs, net of taxes	$	323			$	528		$	—			$	—
	Net actuarial (gain) loss, net of taxes	37,479				52,472			(5,584		)		(715		)
	Transition obligation, net of taxes	—				—			27				222
	Total accumulated other comprehensive income (loss)	$	37,802			$	53,000		$	(5,557	)		$	(493	)
	Alagasco recognized a regulatory asset of $58.2 million and $89.5 million as of December 31, 2013 and 2012, respectively, for the portion of the pension plan obligation to be recovered through rates in future periods. Alagasco also recognized a regulatory liability of $26.2 million and $1.2 million as of December 31, 2013 and 2012, respectively, for the portion of the postretirement health care and life insurance benefit obligation to be refunded through rates in future periods.
	Other investment assets designated for payment of the nonqualified supplemental retirement plans were as follows:
		December 31, 2013
	(in thousands)	Level 1			Level 2			Level 3			Total
	Insurance contracts	$	—		$	14,805		$	—		$	14,805
	United States equities	5,579			—			—			5,579
	Global equities	2,338			—			—			2,338
	Fixed income	—			11,039			—			11,039
	Total	$	7,917		$	25,844		$	—		$	33,761
		December 31, 2012
	(in thousands)	Level 1			Level 2			Level 3			Total
	Insurance contracts	$	—		$	7,399		$	5,600		$	12,999
	United States equities	4,741			—			—			4,741
	Global equities	2,109			—			—			2,109
	Fixed income	—			10,219			—			10,219
	Total	$	6,850		$	17,618		$	5,600		$	30,068
	While intended for payment of the nonqualified supplemental retirement plan benefits, these assets remain subject to the claims of the Company’s creditors and are not recognized in the funded status of the plan. These assets are recorded at fair value and included in deferred charges and other in the consolidated balance sheets.
	The following is a reconciliation of insurance contracts in Level 3 of the fair value hierarchy:
	Years ended December 31, (in thousands)	2013			2012			2011
	Balance at beginning of period	$	5,600		$	5,332		$	5,069
	Unrealized gains relating to instruments held at the reporting date	—			268			263
	Transfer out of Level 3	(5,600		)	—			—
	Balance at end of period	$	—		$	5,600		$	5,332
	Changes in Fair Value Levels: The availability of observable market data is monitored to assess the appropriate classification for financial instruments within the fair value hierarchy. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the reporting period. For the year ended December 31, 2013, except for the transfer out of Level 3 noted below, there were no significant transfers in or out of Levels 1, 2, or 3.
	Transfer of Insurance Contracts: The insurance contracts consist of multiple contracts with two insurance companies and are accounted for at fair value at the contracts’ cash surrender values. During 2013, the Company determined that its insurance contracts meet the requirements to be categorized as a Level 2 fair value measurement.
	The components of net periodic benefit cost were as follows:
	Years ended December 31, (in thousands)	2013			2012			2011
	Pension Plans
	Components of net periodic benefit cost:
	Service cost	$	14,173		$	10,527		$	9,173
	Interest cost	11,239			10,801			10,960
	Expected long-term return on assets	(14,731		)	(14,093		)	(15,471		)
	Prior service cost amortization	490			517			496
Actuarial loss amortization	13,979			8,603			6,435
Termination benefit charge	—			—			414
Settlement charge	1,373			—			—
Net periodic expense	$	26,523		$	16,355		$	12,007
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	1,694		$	1,853		$	1,769
Interest cost	3,504			4,248			4,443
Expected long-term return on assets	(5,024		)	(4,438		)	(4,418		)
Actuarial (gain) loss amortization	(120		)	37			—
Transition obligation amortization	1,296			1,917			1,917
Curtailment gain	(1,229		)	—			—
Net periodic expense	$	121		$	3,617		$	3,711
Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows:
Years ended December 31, (in thousands)	2013			2012			2011
Pension Plans
Net actuarial (gain) loss experienced during the year	$	(14,138	)	$	28,748		$	14,312
Net actuarial loss recognized as expense	(8,934		)	(4,908		)	(3,755		)
Prior service cost recognized as expense	(311		)	(340		)	(298		)
Total recognized in other comprehensive income (loss)	(23,383		)	23,500			10,259
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	(8,057	)	$	(1,787	)	$	2,111
Net actuarial gain recognized as expense	550			—			—
Transition obligation recognized as expense	(283		)	(294		)	(286		)
Total recognized in other comprehensive income (loss)	$	(7,790	)	$	(2,081	)	$	1,825
Net retirement expense for Alagasco was $12.1 million, $7.8 million and $5.2 million for the years ended December 31, 2013, 2012 and 2011, respectively. In conjunction with the sale of its Black Warrior Basin coalbed methane properties in Alabama, the Company recognized a curtailment gain of $1.2 million in the fourth quarter of 2013. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was expensed and $46,000 was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the fourth quarter of 2013, the Company incurred a settlement charge of $0.8 million for the payment of lump sums from a defined benefit pension plan. In the first quarter of 2011, the Company recognized a termination benefit charge of $0.4 million to provide for early retirement of certain non-highly compensated employees. Net periodic postretirement benefit cost for Alagasco was $0.8 million, $2.7 million and $2.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
Estimated amounts to be amortized from accumulated other comprehensive income into pension cost during 2014 are as follows:
(in thousands)
Amortization of prior service cost	$	314
Amortization of net actuarial loss	$	5,422
Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2014 are as follows:
(in thousands)
Amortization of net transition obligation	$	42
Amortization of net actuarial gain	$	(593	)
The Company has a long-term disability plan covering most employees. The Company had expense for the years ended December 31, 2013, 2012 and 2011 of $0.6 million, $0.7 million and $0.5 million, respectively.
Assumptions: The weighted average rate assumptions to determine net periodic benefit costs were as follows:
Years ended December 31,	2013		2012		2011
Pension Plans
Discount rate	3.63	%	4.52	%	4.89	%
Expected long-term return on plan assets	7	%	7	%	7.25	%
Rate of compensation increase for pay-related plans	3.71	%	3.59	%	3.75	%
Postretirement Benefit Plans
Discount rate	4.26	%	4.95	%	5.45	%
Expected long-term return on plan assets	7	%	7	%	7.25	%
Rate of compensation increase	3.7	%	3.55	%	3.61	%
The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:
Years ended December 31,	2013		2012
Pension Plans
Discount rate	4.31	%	3.47	%
Rate of compensation increase for pay-related plans	3.63	%	3.71	%
Postretirement Benefit Plans
Discount rate	4.95	%	4.15	%
Rate of compensation increase for pay-related plans	3.6	%	3.7	%
The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:
As of December 31,	2013		2012
Health care cost trend rate assumed for next year	6.5	%	6.75	%
Rate to which the cost trend rate is assumed to decline	5	%	5	%
Year that rate reaches ultimate rate	2020		2020
Assumed health care cost trend rates used in determining the accumulated postretirement benefit obligation have an effect on the amounts reported. For example, revising the weighted average health care cost trend rate by 1 percentage point would have the following effects:
(in thousands)
	1-Percentage Point Decrease			1-Percentage Point Increase
Effect on total of service and interest cost	$	(280	)	$	336
Effect on net postretirement benefit obligation	$	(764	)	$	759
Investment Strategy: The Company employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.
The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily.
The Company seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
The Company’s weighted average plan asset allocations by asset category were as follows:
	Pension						Postretirement Benefits
As of December 31,	Target		2013		2012		Target		2013		2012
Asset category:
Equity securities	41	%	34	%	41	%	60	%	61	%	60	%
Debt securities	38	%	28	%	38	%	40	%	39	%	40	%
Other	21	%	38	%	21	%	—	%	—	%	—	%
Total	100	%	100	%	100	%	100	%	100	%	100	%
Equity securities for pension and postretirement benefits do not include the Company’s common stock.
Plan assets included in the funded status of the pension plans were as follows:
	December 31, 2013
(in thousands)	Level 1			Level 2			Level 3			Total
United States equities	$	34,117		$	8,080		$	—		$	42,197
Global equities	20,153			13,256			—			33,409
Fixed income	—			61,121			—			61,121
Alternative investments	—			37,292			—			37,292
Cash and cash equivalents	5,970			39,545			—			45,515
Total	$	60,240		$	159,294		$	—		$	219,534
	December 31, 2012
(in thousands)	Level 1			Level 2			Level 3			Total
United States equities	$	41,907		$	9,072		$	—		$	50,979
Global equities	23,782			10,697			—			34,479
Fixed income	—			78,806			—			78,806
Alternative investments	—			27,659			14,500			42,159
Cash and cash equivalents	—			3,001			—			3,001
Total	$	65,689		$	129,235		$	14,500		$	209,424
United States equities consist of mutual and commingled funds with varying strategies. Such strategies include stock investments across market capitalizations and investment styles. Global equities consist of mutual funds and a limited partnership that invest in United States and non-United States securities broadly diversified across mostly developed markets but with some tactical exposure to emerging markets. Fixed income securities consist of mutual funds and separate accounts. Fixed income securities are well diversified with allocations to investment grade and non-investment grade issues and issues that provide both intermediate and longer duration exposure. Alternative investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative investments are meant to serve as a risk reducer at the total portfolio level as they provide asset class exposures not found elsewhere in the portfolio.
The following is a reconciliation of plan assets in Level 3 of the fair value hierarchy:
Years ended December 31, (in thousands)	2013			2012			2011
Balance at beginning of period	$	14,500		$	17,399		$	26,841
Unrealized gains (losses)	—			992			(752		)
Unrealized gains relating to instruments held at the reporting date	—			242			635
Settlements	—			(4,948		)	(9,604		)
Purchases	—			815			279
Transfer out of Level 3	(14,500		)	—			—
Balance at end of period	$	—		$	14,500		$	17,399
Changes in Fair Value Levels: The availability of observable market data is monitored to assess the appropriate classification for financial instruments within the fair value hierarchy. Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one fair value level to another. In such instances, the transfer is reported at the beginning of the cumulative reporting period. For the year ended December 31, 2013, except for the transfers out of Level 3 noted below, there were no significant transfers in or out of Levels 1, 2, or 3.
Transfer of Alternative Investments: The alternative investments consist of three investments that are measured at net asset value (NAV). NAV per share serves as an estimate for the fair value of an investment as long as certain requirements are met. During 2013, the Company determined that its alternative investments meet those requirements.
Plan assets included in the funded status of the postretirement benefit plans were as follows:
	December 31, 2013
(in thousands)	Level 1			Level 2			Total
United States equities	$	43,054		$	—		$	43,054
Global equities	17,048			—			17,048
Fixed income	—			38,831			38,831
Total	$	60,102		$	38,831		$	98,933
	December 31, 2012
(in thousands)	Level 1			Level 2			Total
United States equities	$	37,482		$	—		$	37,482
Global equities	15,049			—			15,049
Fixed income	—			34,658			34,658
Total	$	52,531		$	34,658		$	87,189
The Company had no Level 3 postretirement benefit plan assets. United States equities consists of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches. Global equities are mutual funds that invest in non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles. Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors.
Cash Flows: There are no required contributions to the qualified pension plans during 2014. 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 million to the qualified pension plans in January 2014. During 2014, the Company may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. The Company expects to make benefit payments of approximately $6.1 million during 2014 to retirees with respect to the nonqualified supplemental retirement plans.
The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:
(in thousands)	Pension Benefits	Postretirement Benefits	Postretirement Benefits – Prescription Drug Subsidy
2014	$66,816	$4,156	($212)
2015	$16,572	$4,219	($218)
2016	$18,174	$4,286	($224)
2017	$22,167	$4,362	($227)
2018	$28,374	$4,426	($231)
2019-2023	$134,584	$22,319	($1,202)
In March 2010, The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 (collectively, Health Care Reform) was signed into law. The impact of the legislation has been estimated and is first reflected in the December 31, 2011 measurement of the post retirement benefit obligation. Energen has applied and been approved for the Early Retiree Reinsurance Program (ERRP). Energen is currently evaluating the application of the ERRP receipts, and therefore, the post retirement benefit obligations have not been reduced to reflect actual or expected receipts under the program.

Common_Stock_Plans

Common Stock Plans	12 Months Ended
	Dec. 31, 2013
Share-based Compensation [Abstract]	'
Common Stock Plans	'
	COMMON STOCK PLANS
	Energen Employee Savings Plan (ESP): A majority of Company employees are eligible to participate in the ESP by electing to contribute a portion of their compensation to the ESP. The Company may match a percentage of the contributions and make these contributions in Company common stock or in funds for the purchase of Company common stock. Employees may diversify 100 percent of their ESP Company stock account into other ESP investment options. The ESP also contains employee stock ownership plan provisions. At December 31, 2013, total shares reserved for issuance equaled 1,080,108. Expense associated with Company contributions to the ESP was $8.0 million, $7.8 million and $6.8 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	Stock Incentive Plan: The Stock Incentive Plan provided for the grant of incentive stock options and non-qualified stock options to officers and key employees. The Stock Incentive Plan also provided for the grant of performance share awards and restricted stock. The Company has typically funded options, restricted stock obligations and performance share obligations through original issue shares and restricted stock through treasury shares. Under the Stock Incentive Plan, 8,600,000 shares of Company common stock were reserved for issuance with 2,921,392 remaining for issuance as of December 31, 2013.
	Performance Share Awards: The Stock Incentive Plan provided 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 provided that payment of earned performance share awards be made in the form of Company common stock.
	No performance share awards were granted in 2012 or 2011. A summary of performance share award activity as of December 31, 2013, and transactions during the year ended December 31, 2013 is presented below:
		Stock Incentive Plan
		Shares		Weighted
				Average Price
	Nonvested at December 31, 2012	—		$	—
	Granted (two-year vesting period)	86,221		61.14
	Granted (three-year vesting period)	82,606		62.96
	Forfeited	(8,008	)	60.03
	Nonvested at December 31, 2013	160,819		$	62.13
	The Company recorded expense of $4.0 million for the year ended December 31, 2013 for performance share awards with a related deferred income tax benefit of $1.5 million. During the years ended December 31, 2012 and 2011, the Company recorded no expense for performance share awards. As of December 31, 2013, there was $5.5 million of total unrecognized compensation cost related to performance share awards. These awards have a remaining weighted average requisite service period of 1.49 years.
	Stock Options: The Stock Incentive Plan provided for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provided for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date.
	A summary of stock option activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 are presented below:
		Stock Incentive Plan
		Shares		Weighted Average Exercise Price
	Outstanding at December 31, 2010	1,276,043		$	40.16
	Granted	293,978		54.99
	Exercised	(227,405	)	32.33
	Forfeited	(4,375	)	35.35
	Outstanding at December 31, 2011	1,338,241		44.77
	Granted	371,040		54.11
	Exercised	(58,471	)	24.55
	Forfeited	(2,335	)	46.45
	Outstanding at December 31, 2012	1,648,475		47.58
	Granted	137,762		49.22
	Exercised	(590,119	)	40.92
	Forfeited	(5,074	)	51.85
	Outstanding at December 31, 2013	1,191,044		$	51.06
	Exercisable at December 31, 2011	677,753		$	43.72
	Exercisable at December 31, 2012	987,733		$	43.75
	Exercisable at December 31, 2013	713,445		$	49.8
	Remaining reserved for issuance at December 31, 2013	2,921,392		—
	The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values:
	Grant date	10/15/13	1/24/13		1/25/12		1/26/11
	Awards granted	3,686	134,076		371,040		293,978
	Fair market value of stock option at grant	$30.53	$16.66		$18.79		$19.65
	Expected life of award	5.8 years	5.8 years		5.8 years		5.8 years
	Risk-free interest rate	1.79%	1.01	%	1.07	%	2.45	%
	Annualized volatility rate	40.60%	40.3	%	39.6	%	37.8	%
	Dividend yield	0.70%	1.2	%	1	%	1	%
	The Company recorded stock option expense of $3.6 million, $7.0 million and $5.6 million during the years ended December 31, 2013, 2012 and 2011, respectively, with a related deferred tax benefit of $1.4 million, $2.6 million and $2.1 million, respectively.
	The total intrinsic value of stock options exercised during the year ended December 31, 2013, was $15.7 million. During the year ended December 31, 2013, the Company received cash of $17.8 million from the exercise of stock options. Total intrinsic value for outstanding options as of December 31, 2013, was $23.5 million and $14.9 million for exercisable options. The fair value of options vested for the year ended December 31, 2013 was $5.8 million. As of December 31, 2013, there was $0.5 million of unrecognized compensation cost related to outstanding nonvested stock options.
	The following table summarizes options outstanding as of December 31, 2013:
	Stock Incentive Plan
	Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
	$46.45	59,330	3.00 years
	$60.56	99,965	4.00 years
	$29.79	78,222	5.00 years
	$46.69	203,469	6.00 years
	$54.99	266,166	7.00 years
	$54.11	349,754	8.00 years
	$48.36	130,452	9.00 years
	$80.48	3,686	9.83 years
	$29.79-$80.48	1,191,044	6.77 years
	The weighted average remaining contractual life of currently exercisable stock options is 5.89 years as of December 31, 2013.
	Restricted Stock: In addition, the Stock Incentive Plan provided for the grant of restricted stock which have been valued based on the quoted market price of the Company’s common stock at the date of grant. Restricted stock awards have a three year vesting period. A summary of restricted stock activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 is presented below:
		Stock Incentive Plan
		Shares		Weighted Average Price
	Nonvested at December 31, 2010	24,150		$	35.49
	Vested	(14,875	)	30.81
Nonvested at December 31, 2011	9,275		42.99
Granted	11,115		45.24
Vested	(9,275	)	42.97
Nonvested at December 31, 2012	11,115		45.24
Granted	52,650		52.34
Forfeited	(1,247	)	48.36
Nonvested at December 31, 2013	62,518		$	51.16
The Company recorded expense of $2.0 million, $0.1 million and $0.1 million for the years ended December 31, 2013, 2012 and 2011, respectively, related to restricted stock, with a related deferred income tax benefit of $746,000, $31,000 and $47,000, respectively. As of December 31, 2013, there was $1.2 million of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a remaining requisite service period of 2.05 years.
Stock Appreciation Rights Plan: The Energen Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Company stock. Officers of the Company are not eligible to participate in this Plan. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. These awards have a three year requisite service period.
A summary of stock appreciation rights activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 are presented below:
	Stock Appreciation Rights Plan
	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2010	656,340		$	38.3
Granted	189,984		54.99
Exercised/forfeited	(69,106	)	41.21
Outstanding at December 31, 2011	777,218		42
Exercised/forfeited	(124,188	)	30.9
Outstanding at December 31, 2012	653,030		44.14
Granted	88,000		48.36
Exercised/forfeited	(363,653	)	39.66
Outstanding at December 31, 2013	377,377		$	49.48
The Company issued the following awards with stock appreciation rights. The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. On December 19, 2013, the Company modified certain stock appreciation rights subsequent to the original grant date. For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2013:
Grant date	1/24/13	1/24/13	1/26/11	1/26/11	1/27/10
		(modified)		(modified)
Awards granted	87,069	931	182,199	7,785	171,749
Fair market value of award	$34.66	$27.89	$27.07	$24.21	$30.10
Expected life of award	5.6 years	2.5 years	3.6 years	2.5 years	3.0 years
Risk-free interest rate	2.04%	0.56%	1.06%	0.56%	0.80%
Annualized volatility rate	40.60%	40.60%	40.60%	40.60%	40.60%
Dividend yield	0.80%	0.80%	0.80%	0.80%	0.80%
Grant date	2/13-16/2009	1/28/09	2/4/08	2/1/07
Awards granted	3,292	305,257	67,093	85,906
Fair market value of award	$39.87	$41.18	$18.50	$27.03
Expected life of award	2.5 years	2.5 years	2.0 years	1.5 years
Risk-free interest rate	0.58%	0.58%	0.39%	0.23%
Annualized volatility rate	40.60%	40.60%	40.60%	40.60%
Dividend yield	0.80%	0.80%	0.80%	0.80%
Expense associated with stock appreciation rights of $1.5 million and $4.3 million was recorded for the years ended December 31, 2013 and 2011. Income associated with stock appreciation rights of $1.0 million was recorded for the year ended December 31, 2012. During the year ended December 31, 2013, the total intrinsic value of stock appreciation rights exercised was $8.5 million. During the year ended December 31, 2013, the Company paid $5.8 million in settlement of stock appreciation rights.
Petrotech Incentive Plan: The Energen Resources’ Petrotech Incentive Plan provided for the grant of stock equivalent units which may include market conditions. Officers of the Company are not eligible to participate in this Plan. These awards are liability awards which are re-measured each reporting period and settle in cash at completion of the vesting period. Stock equivalent units with service conditions were valued based on the Company’s stock price at the end of the period adjusted to remove the present value of future dividends.
A summary of Petrotech unit activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 are presented below:
		Petrotech Incentive Plan
		Shares
Outstanding at December 31, 2010		8,205
Granted (three-year vesting period)		6,314
Paid		(1,914	)
Forfeited		(1,544	)
Outstanding at December 31, 2011		11,061
Granted (three-year vesting period)		102,349
Granted (two-year vesting period)		3,768
Granted (18 month vesting period)		40,822
Paid		(3,281	)
Forfeited		(13,476	)
Outstanding at December 31, 2012		141,243
Granted (three-year vesting period)		92,418
Granted (17 month vesting period)		2,952
Paid		(36,792	)
Forfeited		(26,529	)
Outstanding at December 31, 2013		173,292
None of the awards issued included a market condition. Energen Resources recognized expense of $6.2 million, $2.6 million and $0.2 million during 2013, 2012 and 2011, respectively, related to these units.
1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Company’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of the Company’s creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the consolidated statements of shareholders’ equity. As of December 31, 2013 there were 695,140 shares reserved for issuance from the 1997 Deferred Compensation Plan.
1992 Energen Corporation Directors Stock Plan: In 1992 the Company adopted the Energen Corporation Directors Stock Plan to pay a portion of the compensation of its non-employee directors in shares of Company common stock. Under the Plan, 13,500 shares, 11,120 shares and 12,420 shares were awarded during the years ended December 31, 2013, 2012 and 2011, respectively, leaving 138,284 shares reserved for issuance as of December 31, 2013.
Stock Repurchase Program: By resolution adopted May 25, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board authorized the Company to repurchase up to 12,564,400 shares of the Company’s common stock. There were no shares repurchased pursuant to its repurchase authorization for the years ended December 31, 2013, 2012 and 2011. As of December 31, 2013, a total of 8,992,700 shares remain authorized for future repurchase. The Company also from time to time acquires shares in connection with participant elections under the Company’s stock compensation plans. For the years ended December 31, 2013, 2012 and 2011, the Company acquired 14,766 shares, 5,459 shares and 12,867 shares, respectively, in connection with its stock compensation plans.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	COMMITMENTS AND CONTINGENCIES
	Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 7.1 million barrels of oil equivalent (MMBOE) through September 2017.
	Energen Resources entered into an agreement which commenced on January 15, 2012 and expires in January 2015 to secure a drilling rig necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of this drilling rig, Energen Resources’ total resulting exposure could be as much as $3.9 million depending on the contractor’s ability to remarket the drilling rig.
	Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $171 million through September 2024. During the years ended December 31, 2013, 2012 and 2011, Alagasco recognized approximately $50 million, $51 million and $51 million, respectively, of current-year 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 134 Bcf through August 2020.
	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 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 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 December 31, 2013.
	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 and 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.
	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 December 31, 2013.
	Lease Obligations: Alagasco leases the Company’s headquarters building over a 25-year term ending January 31, 2024 and the related lease is accounted for as an operating lease. Under the terms of the lease, Alagasco has a renewal option; the lease does not contain a bargain purchase price or a residual value guarantee. Effective July 1, 2013, Alagasco subleased the Company’s headquarters to Energen. Prior to July 2013, approximately 49 percent of the total headquarters lease payments were charged to Energen. As of July 2013, approximately 77 percent of the total headquarters lease payments are charged to Energen due to an increase in office space utilized by Energen. Alagasco recognizes Energen’s payment of rent expense in other income with an offset in other expense. These amounts are eliminated on the consolidated statements of income. Alagasco entered into a new lease for the current Alagasco corporate headquarters in July 2013 which is classified as an operating lease. Energen’s total lease payments included as operating lease expense were $25.0 million, $20.9 million and $19.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. Minimum future rental payments required after 2013 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
	Years Ending December 31, (in thousands)
	2014	2015	2016	2017	2018	2019 and thereafter
	$5,270	$4,940	$4,391	$3,980	$2,409	$10,637
	Alagasco’s total payments related to leases included as operating expense were $2.4 million, $2.1 million and $2.3 million for the years ended December 31, 2013, 2012 and 2011, respectively. These amounts are net of approximately $0.7 million, $1.0 million and $1.0 million of lease expense paid by Energen in 2013, 2012 and 2011, respectively. Minimum future rental payments required after 2013 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
	Years Ending December 31, (in thousands)
	2014	2015	2016	2017	2018	2019 and thereafter
	$4,291	$4,062	$3,994	$3,979	$2,409	$10,637
	Included in the table above are approximately $16.2 million of payments associated with leasing of the Company’s headquarters, which are expected to be reimbursed to Alagasco by Energen through the remaining term of the related lease.

Financial_Instruments_and_Risk

Financial Instruments and Risk Management	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Financial Instruments and Risk Management	'
	FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
	Financial Instruments: The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, approximates $1,420.7 million and $1,255.8 million and has a carrying value of $1,403.9 million and $1,154.0 million at December 31, 2013 and 2012, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, approximates $258.8 million and $284.7 million and has a carrying value of $249.9 million and $250.0 million at December 31, 2013 and 2012, respectively. The fair values were based on market prices of similar 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.
	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 counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheet. 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 December 31, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through October 2014 with an aggregate purchase price of $0.5 million and a market value of $0.6 million.
	Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At December 31, 2013 and 2012, Alagasco’s finance receivable totaled approximately $10.8 million and $10.7 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and 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 the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.4 million and $0.5 million as of December 31, 2013 and 2012, respectively.
	The following table sets forth a summary of changes in the allowance for credit losses as follows:
	(in thousands)
	Allowance for credit losses as of December 31, 2011	$	421
	Provision	49
	Allowance for credit losses as of December 31, 2012	470
	Provision	(47		)
	Allowance for credit losses as of December 31, 2013	$	423
	Risk Management: At December 31, 2013, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at December 31, 2013. The two largest counterparty net gain positions at December 31, 2013, Macquarie Bank Limited and J Aron & Company, constituted approximately $8.6 million and $5.3 million of Energen Resources’ total net loss on fair value of derivatives.
	The following table details the fair values of commodity contracts by business segment on the balance sheets:
	(in thousands)	December 31, 2013
		Oil and Gas Operations			Natural Gas Distribution		Total
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	36,224			—		36,224
	Long-term asset derivative instruments	7,992			—		7,992
	Total derivative assets	44,216			—		44,216
	Accounts receivable	(18,761	)	*	—		(18,761	)
	Long-term asset derivative instruments	(2,553	)	*	—		(2,553	)
	Accounts payable	(30,302	)		—		(30,302	)
	Total derivative liabilities	(51,616	)		—		(51,616	)
	Total derivatives not designated	(7,400	)		—		(7,400	)
	(in thousands)	December 31, 2012
		Oil and Gas Operations				Natural Gas Distribution			Total
	Derivative assets or (liabilities) designated as hedging instruments
	Accounts receivable	$	87,514			$	—		$	87,514
	Long-term asset derivative instruments	37,954				—			37,954
	Total derivative assets	125,468				—			125,468
	Accounts receivable	(37,326		)	*	—			(37,326		)
	Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
	Long-term liability derivative instruments	(8,726		)		—			(8,726		)
	Total derivative liabilities	(52,862		)		—			(52,862		)
	Total derivatives designated	72,606				—			72,606
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	14,604				—			14,604
	Long-term asset derivative instruments	9,433				—			9,433
	Total derivative assets	24,037				—			24,037
	Accounts payable	—				(2,593		)	(2,593		)
	Long-term liability derivative instruments	(874		)		—			(874		)
	Total derivative liabilities	(874		)		(2,593		)	(3,467		)
	Total derivatives not designated	23,163				(2,593		)	20,570
	Total derivatives	$	95,769			$	(2,593	)	$	93,176
	* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.
	The Company had a net $8.2 million and a net $28.4 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in other comprehensive income as of December 31, 2013 and 2012, respectively.
	The following table details the effect of derivative commodity instruments designated as hedging instruments on the financial statements:
	Years ended December 31, (in thousands)	Location on Income Statement	2013			2012			2011
	Net gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($6,660), $40,720 and $41,399	—	$	(10,866	)	$	66,438		$	67,547
	Gain reclassified from accumulated OCI into	Operating revenues	$	34,293		$	52,694		$	26,326
	income (effective portion)
	Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	835		$	(5,340	)	$	(2,767	)
	The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:
	Years ended December 31, (in thousands)	Location on Income Statement	2013			2012			2011
	Gain (loss) recognized in income on derivative	Operating revenues	$	(73,980	)	$	61,841		$	(37,587	)
	As of December 31, 2013, $13.4 million of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, net of tax, are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of December 31, 2013, the Company had 51.8 billion cubic feet (Bcf) and 6.0 Bcf of natural gas hedges which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 9.8 million barrels (MMBbl) and 5.8 MMBbl of oil hedges which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 1.9 million gallons (MMgal) of natural gas liquid hedges which expire during 2014 that are considered mark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $4.5 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being held for sale or sold.
	As of December 31, 2013, Energen Resources entered into the following transactions for 2014 and subsequent years:
	Production Period	Total Hedged Volumes		Average Contract	Description
				Price
	Natural Gas
	2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
		31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
		9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	6	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
Oil
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	5,760	MBbl	$88.85 Bbl	NYMEX Swaps
As of December 31, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010.
The following sets forth derivative assets and liabilities that were measured at fair value on a recurring basis:
	December 31, 2013
(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	)
	December 31, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(3,629	)	$	68,421		$	64,792
Noncurrent assets	18,899			21,678			40,577
Current liabilities	(2,593		)	—			(2,593		)
Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
Net derivative asset	$	4,157		$	89,019		$	93,176
* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.
As of December 31, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which were classified as Level 2 fair values and are included in the above table as current liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2013 and 2012.
The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $19 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $19 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 table below sets forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:
Years ended December 31, (in thousands)	2013			2012			2011
Balance at beginning of period	$	89,019		$	65,801		$	42,755
Realized gains	55,210			63,720			52,716
Unrealized gains (losses) relating to instruments held at the reporting date*	(71,367		)	22,160			23,980
Settlements during period	(54,573		)	(62,662		)	(53,650		)
Balance at end of period	$	18,289		$	89,019		$	65,801
*Includes $7.6 million in mark-to-market losses, $19.9 million in mark-to-market gains and $5.2 million in mark-to-market losses for the years ended December 31, 2013, 2012 and 2011, 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 December 31, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2014	$	18,159		Discounted Cash Flow	Forward Basis	($0.17 - $0.20) Mcf
2015	$	1,056		Discounted Cash Flow	Forward Basis	($0.26) Mcf
Natural Gas Basis - Permian
2014	$	(1,948	)	Discounted Cash Flow	Forward Basis	($0.18 - $0.20) Mcf
Natural Gas Liquids
2014	$	1,022		Discounted Cash Flow	Forward Price	$0.80 - $0.81 Gal
*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.
The tables below set forth information about the offsetting of derivative assets and liabilities as follows:
	31-Dec-13
										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
	31-Dec-12
										Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets			Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	149,504		$	(44,135	)	$	105,369		$	—	$	—	$	105,369
Derivative liabilities	$	56,328		$	(44,135	)	$	12,193		$	—	$	—	$	12,193
Concentration of Credit Risk: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil and natural gas to energy marketing companies. Such sales are typically made on an unsecured credit basis with payment due the month following delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. Energen Resources considers the credit quality of its purchasers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The two largest oil and gas purchasers accounted for approximately 35 percent and 12 percent of Energen Resources’ accounts receivable for commodity sales as of December 31, 2013. Energen Resources’ other purchasers each accounted for less than 9 percent of these accounts receivable as of December 31, 2013. During the year ended December 31, 2013, Plains Marketing, LP, accounted for approximately 25 percent of consolidated total operating revenues. All other oil and gas purchasers each accounted for less than 10 percent of consolidated total operating revenues for the year ended December 31, 2013.
Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 422,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.

Reconciliation_of_Earnings_Per

Reconciliation of Earnings Per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Reconciliation of Earnings Per Share	'
	RECONCILIATION OF EARNINGS PER SHARE
	Years ended December 31,
	(in thousands, except per share amounts)				2013						2012					2011
		Net			Shares		Per Share Amount		Net		Shares	Per Share Amount		Net		Shares	Per Share Amount
		Income							Income					Income
	Basic EPS	$	204,554		72,318		$	2.83	$	253,562	72,119	$	3.52	$	259,624	72,056	$	3.6
	Effect of dilutive securities
	Stock options				112						196					270
	Non-vested restricted stock				20						1					6
	Performance share awards				21						—					—
	Diluted EPS	$	204,554		72,471		$	2.82	$	253,562	72,316	$	3.51	$	259,624	72,332	$	3.59
	The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive.
	Years ended December 31, (in thousands)	2013		2012		2011
	Stock options	134,138		849,583		293,978
	Non-vested restricted stock	6,529		—		—
	Performance share awards	4,121		—		—

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	ASSET RETIREMENT OBLIGATIONS
	The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the period incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company. Revisions in estimates to the ARO result from revisions to the estimated timing or amount of the underlying cash flows. In 2013, 2012 and 2011, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:
	(in thousands)
	Balance as of December 31, 2010	$	97,415
	Liabilities incurred	4,627
	Liabilities settled	(1,539		)
	Accretion expense (including discontinued operations of $1,138)	6,837
	Balance as of December 31, 2011	107,340
	Liabilities incurred	3,994
	Liabilities settled	(845		)
	Accretion expense (including discontinued operations of $1,195)	7,534
	Balance as of December 31, 2012	118,023
	Liabilities incurred	2,772
	Liabilities settled	(5,525		)
	Accretion expense (including discontinued operations of $1,197)	8,192
	Reclassification associated with held for sale properties*	(14,929		)
	Balance as of December 31, 2013	$	108,533
	* Asset retirement obligation associated with North Louisiana/East Texas properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.
	The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $27.5 million and $24.9 million to purge and cap its gas pipelines upon abandonment and to remediate other related obligations, as a regulatory liability as of December 31, 2013 and 2012, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $4.6 million and $3.3 million as of December 31, 2013 and 2012, respectively, are included as regulatory assets

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Supplemental Cash Flow Information	'
	SUPPLEMENTAL CASH FLOW INFORMATION
	Supplemental information concerning Energen’s cash flow activities was as follows:
	Years ended December 31, (in thousands)	2013			2012		2011
	Interest paid, net of amount capitalized	$	65,143		$	61,379	$	33,601
	Income taxes paid	$	25,081		$	17,170	$	9,432
	Noncash investing activities:
	Accrued development, exploration costs and other capital	$	99,128		$	120,024	$	72,030
	Capitalized depreciation	$	66		$	80	$	93
	Capitalized asset retirement obligations costs	$	3,574		$	4,409	$	4,927
	Allowance for funds used during construction	$	698		$	623	$	807
	Capital lease obligations	$	—		$	5,072	$	—
	Noncash financing activities:
	Issuance of common stock for employee benefit plans	$	1,015		$	838	$	822
	Treasury stock acquired in connection with tax withholdings	$	977		$	277	$	713
	Supplemental information concerning Alagasco’s cash flow activities was as follows:
	Years ended December 31, (in thousands)	2013			2012		2011
	Interest paid, net of amount capitalized	$	13,465		$	13,513	$	12,385
	Income taxes paid	$	23,138		$	16,796	$	5,143
	Interest expense (revenue) on affiliated company debt, net	$	(18	)	$	295	$	376
	Noncash investing activities:
	Accrued property, plant and equipment costs	$	5,505		$	3,536	$	2,229
	Capitalized depreciation	$	66		$	80	$	93
	Capitalized asset retirement obligations costs	$	802		$	415	$	300
	Allowance for funds used during construction	$	698		$	623	$	807

Acquisition_and_Dispositions_o

Acquisition and Dispositions of Oil and Gas Properties	12 Months Ended
	Dec. 31, 2013
Acquisition and Dispositions of Oil and Gas Properties [Abstract]	'
Acquisition and Dispositions of Oil and Gas 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.
	On February 21, 2012, Energen Resources entered into a definitive agreement with BHP Billiton (BHP) to buy a 50 percent undivided interest in three existing wells in Reeves County, Texas, from Energen Resources for approximately $18 million. Following the purchase of the wells, BHP completed two of the wells and earned a 50 percent undivided interest in 4,829 net acres. The agreement also included the option for BHP to purchase from Energen Resources a 50 percent undivided interest in 51,720 net acres in the Permian Basin. On May 1, 2012, BHP elected not to exercise the option.
	On February 14, 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million. This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.2 MMBOE. Of the proved reserves acquired, an estimated 81 percent are undeveloped. Approximately 64 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.
	The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (including the effects of closing adjustments).
	(in thousands)
	Consideration given
	Cash (net)	$	67,615
	Recognized amounts of identifiable assets acquired and liabilities assumed
	Proved properties	$	65,581
	Unproved leasehold properties	911
	Accounts receivable	1,358
	Accounts payable	(25		)
	Asset retirement obligation	(210		)
	Total identifiable net assets	$	67,615
	Included in the Company’s consolidated results of operations for the year ended December 31, 2012, were $11.7 million of operating revenues and $3.1 million in operating income resulting from the operation of the properties acquired above.
	In December 2012, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $18.7 million. During 2012, Energen also completed a total of approximately $18 million in various purchases of unproved leasehold properties.
	On December 27, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $60 million. This purchase had an effective date of July 1, 2011. Energen acquired total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.
	The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011 (including the effects of closing adjustments).
	(in thousands)
	Consideration given
	Cash (net)	$	60,017
	Recognized amounts of identifiable assets acquired and liabilities assumed
	Proved properties	$	36,068
	Unproved leasehold properties	23,686
	Accounts receivable	680
	Accounts payable	(244		)
	Asset retirement obligation	(173		)
	Total identifiable net assets	$	60,017
	The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.
	On November 16, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $162 million. This purchase had an effective date of August 1, 2011. Energen acquired total proved reserves of approximately 13.6 MMBOE. Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.
	The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011 (including the effects of closing adjustments).
	(in thousands)
	Consideration given
	Cash (net)	$	161,967
	Recognized amounts of identifiable assets acquired and liabilities assumed
	Proved properties	$	151,544
	Unproved leasehold properties	7,883
	Accounts receivable	3,070
	Accounts payable	(388		)
	Asset retirement obligation	(142		)
	Total identifiable net assets	$	161,967
	The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.
	In July 2011, Energen completed the purchase of properties in the Permian Basin for a cash purchase price of approximately $20 million. In April 2011, Energen completed the purchase of unproved leasehold properties for a cash purchase price of approximately $37 million covering an estimated 11,000 net acres in the Permian Basin.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Discontinued Operations	'
	DISCONTINUED OPERATIONS
	In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company recorded a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013 which is 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.
	In January 2014, Energen Resources signed a purchase and sale agreement on its North Louisiana/East Texas natural gas and oil properties for $31.5 million (subject to closing adjustments). The Company expects to complete the sale in the first quarter of 2014 and will use the proceeds 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 third and fourth quarters of $24.6 million pre-tax and $5.2 million pre-tax, respectively, to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. The non-cash impairment writedowns are reflected in gain on disposal of discontinued operations in the year ended December 31, 2013. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. 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.
	The following table details held-for-sale properties by major classes of assets and liabilities:
	(in thousands)	December 31, 2013
		Black Warrior Basin			North Louisiana/East Texas			Total
	Accounts receivable	$	2,829		$	1,272		$	4,101
	Inventories	—			68			68
	Oil and gas properties	—			348,379			348,379
	Less accumulated depreciation, depletion and amortization	—			(301,609		)	(301,609		)
	Other property, net	—			165			165
	Total assets held-for-sale	2,829			48,275			51,104
	Accounts payable	(1,732		)	(11		)	(1,743		)
	Royalty payable	(550		)	(869		)	(1,419		)
	Other current liabilities	(379		)	(21		)	(400		)
	Other long-term liabilities	—			(14,983		)	(14,983		)
	Total liabilities held-for-sale	(2,661		)	(15,884		)	(18,545		)
	Total held-for-sale properties	$	168		$	32,391		$	32,559
	During the first quarter of 2012, Energen Resources recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss from discontinued operations for the year ended December 31, 2012. The impairment was caused by the impact of lower future natural gas prices. This impairment writedown is classified as Level 3 fair value.
	Gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. Accordingly, the results of operations for certain held-for-sale properties were reclassified and reported as discontinued operations for all prior periods presented. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.
	Years ended December 31, (in thousands, except per share data)	2013			2012			2011
	Oil and gas revenues	$	60,191		$	76,350		$	110,366
	Pretax income (loss) from discontinued operations	$	10,028		$	(2,373	)	$	54,698
	Income tax expense (benefit)	2,215			(715		)	19,379
	Income (Loss) From Discontinued Operations	$	7,813		$	(1,658	)	$	35,319
	Gain on disposal of discontinued operations, net	$	5,605		$	—		$	—
	Income tax expense	2,011			—			—
	Gain on Disposal of Discontinued Operations, net	$	3,594		$	—		$	—
	Total Income (Loss) From Discontinued Operations	$	11,407		$	(1,658	)	$	35,319
	Diluted Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	0.1		$	(0.02	)	$	0.49
	Gain on Disposal of Discontinued Operations, net	0.05			—			—
	Total Income (Loss) From Discontinued Operations	$	0.15		$	(0.02	)	$	0.49
	Basic Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	0.11		$	(0.02	)	$	0.49
	Gain on Disposal of Discontinued Operations, net	0.05			—			—
	Total Income (Loss) From Discontinued Operations	$	0.16		$	(0.02	)	$	0.49

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]	'
Regulatory Assets and Liabilities	'
	REGULATORY ASSETS AND LIABILITIES
	The following table details regulatory assets and liabilities on the consolidated balance sheets:
	(in thousands)	December 31, 2013				December 31, 2012
		Current		Noncurrent		Current		Noncurrent
	Regulatory assets:
	Pension assets	$	325	$	58,243	$	170	$	90,708
	Accretion and depreciation for asset retirement obligation	—		18,046		—		16,536
	Risk management activities	—		—		2,593		—
	Rate recovery of asset removal costs, net	—		4,601		—		3,322
	Enhanced stability reserve	—		4,000		—		—
	Gas supply adjustment	2,406		—		42,726		—
	Other	25		—		26		—
	Total regulatory assets	$	2,756	$	84,890	$	45,515	$	110,566
	Regulatory liabilities:
	RSE adjustment	$	4,690	$	—	$	1,740	$	—
	Unbilled service margin	28,504		—		25,078		—
	Postretirement liabilities	—		26,197		—		1,237
	Refundable negative salvage	15,779		39,663		18,265		53,467
	Asset retirement obligation	—		27,528		—		24,930
	Other	33		737		33		770
	Total regulatory liabilities	$	49,006	$	94,125	$	45,116	$	80,404
	As described in Note 2, Regulatory Matters, Alagasco’s rates are established under the RSE rate-setting process and are based on average equity for the period. Alagasco’s rates are not adjusted to exclude a return on its investment in regulatory assets during the recovery period.

Transactions_with_Related_Part

Transactions with Related Parties	12 Months Ended
	Dec. 31, 2013
Due to Related Parties [Abstract]	'
Transactions with Related Parties	'
	TRANSACTIONS WITH RELATED PARTIES
	The Company allocates certain corporate costs to Energen Resources and Alagasco based on the nature of the expense to be allocated using various factors including, but not limited to, total assets, earnings, or number of employees. The Company’s cash management program seeks to minimize borrowing from outside sources through inter-company lending. Under this program, Alagasco may borrow from but does not lend to affiliates. Alagasco had net trade receivables from affiliates of $4.7 million and $5.7 million at December 31, 2013 and 2012, respectively. Interest income and expense between affiliates is calculated monthly based on the market weighted average interest rate. Alagasco had $18,000 in affiliated company interest revenue during the year ended December 31, 2013. Alagasco had $0.3 million and $0.4 million in affiliated company interest expense during the years ended December 31, 2012 and 2011, respectively.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Accumulated Other Comprehensive Income (Loss)	'
	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
	The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.
	(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
	Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
	Other comprehensive income (loss) before reclassifications	(11,014		)	11,582			568
	Amounts reclassified from accumulated other comprehensive income (loss)	(21,004		)	8,680			(12,324		)
	Change in accumulated other comprehensive income (loss)	(32,018		)	20,262			(11,756		)
	Balance as of December 31, 2013	$	12,178		$	(32,245	)	$	(20,067	)
	The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).
		Year ended
		31-Dec-13
	(in thousands)	Amounts Reclassified			Line Item Where Presented
	Gains and (losses) on cash flow hedges:
	Commodity contracts	$	35,684		Operating revenues
	Interest rate swap	(1,723		)	Interest expense
	Total cash flow hedges	33,961
	Income tax expense	(12,957		)
	Net of tax	21,004
	Pension and postretirement plans:
	Transition obligation	(319		)	Operations and maintenance
	Prior service cost	(257		)	Operations and maintenance
	Actuarial losses*	(12,357		)	Operations and maintenance
	Actuarial losses on settlement charges*	(421		)	Regulatory asset
	Total pension and postretirement plans	(13,354		)
	Income tax expense	4,674
	Net of tax	(8,680		)
	Total reclassifications for the period	$	12,324
	* In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million is recognized in actuarial losses above and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 is recognized in actuarial losses above and $46,000 is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

Recently_Issued_Accounting_Sta

Recently Issued Accounting Standards	12 Months Ended
	Dec. 31, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
Recently Issued Accounting Standards	'
	RECENTLY ISSUED ACCOUNTING STANDARDS
	In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued Accounting Standard Update (ASU) No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 8, Financial Instruments.
	In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 16, Accumulated Other Comprehensive Income (Loss).

Summarized_Quarterly_Financial

Summarized Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Summarized Quarterly Financial Information	'
	SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)
	The Company’s business is seasonal in character. The following data summarizes quarterly operating results.
		Year ended December 31, 2013
	(in thousands, except per share amounts)	First			Second			Third			Fourth
	Operating revenues as originally reported	$	492,679		$	490,057		$	320,406		$	472,733
	Discontinued operations*	(18,663		)	(18,562		)	—			—
	Adjusted operating revenues	$	474,016		$	471,495		$	320,406		$	472,733
	Operating income (loss) as originally reported	$	105,336		$	146,304		$	(4,052	)	$	110,630
	Discontinued operations*	(3,146		)	(3,871		)	—			—
	Adjusted operating income (loss)	$	102,190		$	142,433		$	(4,052	)	$	110,630
	Income (loss) from continuing operations	$	54,694		$	80,614		$	(5,486	)	$	63,325
	Net income (loss)	$	56,692		$	83,067		$	(19,298	)	$	84,093
	Diluted earnings per average common share
	Continuing operations	$	0.76		$	1.11		$	(0.08	)	$	0.87
	Net income (loss)	$	0.78		$	1.15		$	(0.27	)	$	1.15
	Basic earnings per average common share
	Continuing operations	$	0.76		$	1.12		$	(0.08	)	$	0.87
	Net income (loss)	$	0.79		$	1.15		$	(0.27	)	$	1.16
	* As discussed in Note 13, Discontinued Operations, during the fourth quarter of 2013, the Company completed the sale of its Black Warrior Basin coalbed methane properties in Alabama. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013. Also, during the third quarter of 2013, the Company classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations.
		Year ended December 31, 2012
	(in thousands, except per share amounts)	First			Second			Third			Fourth
	Operating revenues as originally reported	$	418,444		$	470,355		$	295,324		$	433,046
	Discontinued operations	(20,255		)	(18,451		)	(18,895		)	(18,749		)
	Adjusted operating revenues	$	398,189		$	451,904		$	276,429		$	414,297
	Operating income as originally reported	$	104,170		$	220,598		$	19,458		$	115,166
	Discontinued operations	16,324			(4,751		)	(5,494		)	(3,557		)
	Adjusted operating income	$	120,494		$	215,847		$	13,964		$	111,609
	Income (loss) from continuing operations	$	67,868		$	128,305		$	(1,505	)	$	60,552
	Net income	$	57,406		$	131,287		$	2,046		$	62,823
	Diluted earnings per average common share
	Continuing operations	$	0.94		$	1.77		$	(0.02	)	$	0.84
	Net income	$	0.79		$	1.82		$	0.03		$	0.87
	Basic earnings per average common share
	Continuing operations	$	0.94		$	1.78		$	(0.02	)	$	0.84
	Net income	$	0.8		$	1.82		$	0.03		$	0.87
	Alagasco’s business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco’s quarterly operating results.
		Year ended December 31, 2013
	(in thousands)	First			Second			Third			Fourth
	Operating revenues	$	237,685		$	104,514		$	48,368		$	142,771
	Operating income (loss)	$	79,293		$	2,219		$	(22,544	)	$	34,800
	Net income (loss)	$	47,222		$	(704	)	$	(8,961	)	$	19,842
		Year ended December 31, 2012
	(in thousands)	First			Second			Third			Fourth
	Operating revenues	$	194,487		$	70,887		$	61,809		$	124,406
	Operating income (loss)	$	78,560		$	4,448		$	(12,743	)	$	22,951
	Net income (loss)	$	46,918		$	326		$	(10,039	)	$	12,197

Oil_and_Gas_Operations_Unaudit

Oil and Gas Operations (Unaudited)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Oil and Gas Operations	'
	OIL AND GAS OPERATIONS (Unaudited)
	Capitalized Costs: The following table sets forth capitalized costs:
	(in thousands)	December 31, 2013			December 31, 2012
	Proved	$	7,043,779		$	6,241,148
	Unproved	168,975			197,979
	Total capitalized costs	7,212,754			6,439,127
	Accumulated depreciation, depletion and amortization	2,078,411			1,765,241
	Capitalized costs, net	$	5,134,343		$	4,673,886
	Costs Incurred: The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:
	Years ended December 31, (in thousands)	2013			2012			2011
	Property acquisition:
	Proved	$	4,661		$	79,862		$	214,993
	Unproved	26,820			58,634			91,888
	Exploration	435,636			419,284			190,854
	Development	655,353			749,256			623,775
	Total costs incurred	$	1,122,470		$	1,307,036		$	1,121,510
	Results of Operations From Producing Activities: The following table sets forth results of the Company’s oil and gas operations from producing activities:
	Years ended December 31, (in thousands)	2013			2012			2011
	Gross revenues*	$	1,206,293		$	1,090,948		$	834,700
	Production (lifting costs)	351,541			278,193			226,361
	Exploration expense	27,942			19,356			12,967
	Depreciation, depletion and amortization	449,700			339,569			210,532
	Accretion expense	6,995			6,339			5,699
	Income tax expense	128,773			160,551			134,564
	Results of operations from producing activities	$	241,342		$	286,940		$	244,577
	* The years ended December 31, 2013, 2012 and 2011 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $58.8 million and a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million, respectively.
	Oil and Gas Operations: The calculation of proved reserves is made pursuant to rules prescribed by the SEC. Such rules, in part, require that proved categories of reserves be disclosed. Reserves and associated values were calculated using twelve-month average prices and current costs for the years ended December 31, 2013, 2012 and 2011. Changes to prices and costs could have a significant effect on the disclosed amount of reserves and their associated values. In addition, the estimation of reserves inherently requires the use of geologic and engineering estimates which are subject to revision as reservoirs are produced and developed and as additional information is available. Accordingly, the amount of actual future production may vary significantly from the amount of reserves disclosed. The proved reserves are located onshore in the United States of America.
	Estimates of physical quantities of oil and gas proved reserves were determined by Company engineers. Ryder Scott Company, L.P. (Ryder Scott) and T. Scott Hickman and Associates, Inc. (T. Scott Hickman), independent oil and gas reservoir engineers, have audited the estimates of proved reserves of natural gas, oil and natural gas liquids that the Company has attributed to its net interests in oil and gas properties as of December 31, 2013. Ryder Scott audited the reserve estimates for coalbed methane in the San Juan basins and substantially all of the Permian Basin reserves. T. Scott Hickman audited the reserves for the North Louisiana and East Texas regions and the conventional reserves in the San Juan Basin. The independent reservoir engineers have issued reports covering approximately 98 percent of the Company’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.
	Year ended December 31, 2013	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
	Proved reserves at beginning of period	809,128		155,348		56,155		346.4
	Revisions of previous estimates	18,465		(680	)	2,211		4.6
	Purchases	282		142		56		0.2
	Extensions and discoveries	50,568		20,517		7,823		36.8
	Production	(70,506	)	(10,378	)	(3,233	)	(25.4	)
	Sales	(88,212	)	(79	)	(1	)	(14.8	)
	Proved reserves at end of period	719,725		164,870		63,011		347.8
	Proved developed reserves at end of period	623,305		113,795		42,087		259.8
	Proved undeveloped reserves at end of period	96,420		51,075		20,924		88
	Year ended December 31, 2012	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
	Proved reserves at beginning of period	957,368		129,578		53,957		343.1
	Revisions of previous estimates	(143,704	)	(8,546	)	(9,557	)	(42.1	)
	Purchases	10,656		7,950		2,569		12.4
	Extensions and discoveries	61,170		35,132		11,759		57.1
	Production	(76,362	)	(8,766	)	(2,573	)	(24.1	)
	Proved reserves at end of period	809,128		155,348		56,155		346.4
	Proved developed reserves at end of period	708,657		105,976		36,440		260.5
	Proved undeveloped reserves at end of period	100,471		49,372		19,715		85.9
	Year ended December 31, 2011	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
	Proved reserves at beginning of period	954,387		103,262		40,601		302.9
	Revisions of previous estimates	(12,823	)	(4,513	)	841		(5.8	)
	Purchases	19,362		12,583		5,055		20.8
	Extensions and discoveries	68,160		24,564		9,637		45.6
	Production	(71,718	)	(6,318	)	(2,177	)	(20.4	)
	Proved reserves at end of period	957,368		129,578		53,957		343.1
	Proved developed reserves at end of period	788,812		83,899		33,154		248.5
	Proved undeveloped reserves at end of period	168,556		45,679		20,803		94.6
	2013 Activities: Energen Resources had upward reserve revisions during 2013 which totaled 4.6 MMBOE including approximately 7 MMBOE related to changes in year-end pricing and downward revisions of approximately 5.3 MMBOE of proved undeveloped reserves of which 4.6 MMBOE are expected to be drilled beyond five years with the remainder no longer expected to be drilled. The San Juan Basin upward reserve revisions of 2.2 MMBOE including 5.9 MMBOE related to changes in year-end pricing and downward revisions of approximately 4.6 MMBOE of proved undeveloped reserves that are expected to be drilled beyond five years. Net upward reserve revisions of 1.2 MMBOE in the Permian Basin were due to improved well performance in certain Wolfberry wells and approximately 0.4 MMBOE related to changes in the year-end pricing and downward revisions of approximately 0.7 MMBOE of proved undeveloped reserves that are no longer expected to be drilled.
	Energen Resources purchased 0.2 MMBOE of reserves during 2013 primarily related to the acquisitions of oil properties in the Permian Basin.
	During 2013, Energen Resources had extensions and discoveries of 36.8 MMBOE of which 45 percent were proved undeveloped reserves and 55 percent were proved developed reserves. Extension drilling resulted in 21.6 MMBOE of discoveries with exploratory drilling providing 15.2 MMBOE of discoveries. The San Juan Basin added 2.3 MMBOE of reserves through 30 pay adds. The Permian Basin added 34.4 MMBOE of reserves primarily through the drilling or identification of 262 well locations.
	During 2013, Energen Resources had sales of 14.8 MMBOE primarily due to the sale of the Black Warrior Basin coalbed methane properties.
	2012 Activities: Energen Resources had downward reserve revisions during 2012 which totaled 42.1 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 5.1 MMBOE of which approximately 5.9 MMBOE related to estimated negative price related revisions partially offset by better well performance. The San Juan Basin downward reserve revisions of 19.7 MMBOE included 22.5 MMBOE in negative price related revisions partially offset by better well performance, lower operating costs and lower fuel usage. Downward reserve revisions of 15.8 MMBOE in the Permian Basin were primarily due to lower than anticipated performance in certain development wells along with 1.0 MMBOE of estimated negative price related revisions.
	Energen Resources purchased 12.4 MMBOE of reserves during 2012 primarily related to the acquisitions of oil properties in the Permian Basin.
	During 2012, Energen Resources had extensions and discoveries of 57.1 MMBOE of which 59 percent were proved undeveloped reserves and 41 percent were proved developed reserves. Extension drilling resulted in 45.6 MMBOE of discoveries with exploratory drilling providing 11.5 MMBOE of discoveries. The San Juan Basin added 0.9 MMBOE of reserves through the drilling or identification of 6 well locations. The Permian Basin added 56.1 MMBOE of reserves primarily through the drilling or identification of 422 well locations.
2011 Activities: Energen Resources had downward reserve revisions during 2011 which totaled 5.8 MMBOE. The Black Warrior Basin had downward reserve revisions totaling 0.3 MMBOE of which approximately 0.7 MMBOE related to estimated negative price related revisions partially offset by other positive revisions of 0.4 MMBOE. The San Juan Basin downward reserve revisions of 2.6 MMBOE included 3.9 MMBOE in negative performance related revisions partially offset by 1.3 MMBOE related to estimated positive price related revisions. Downward reserve revisions of 3.1 MMBOE in the Permian Basin were primarily due to lower than anticipated injection response in certain waterflood units and other performance related adjustments. These downward revisions were partially offset by 1.4 MMBOE of estimated positive price related revisions.
Energen Resources purchased 20.8 MMBOE of reserves during 2011 primarily related to the acquisitions of oil properties in the Permian Basin.
During 2011, Energen Resources had extensions and discoveries of 45.6 MMBOE of which 69 percent were proved undeveloped reserves and 31 percent were proved developed reserves. Extension drilling resulted in 41.1 MMBOE of discoveries with exploratory drilling providing 4.5 MMBOE of discoveries. The San Juan Basin added 5.9 MMBOE of reserves through the drilling or identification of 53 well locations. The Permian Basin added 39.6 MMBOE of reserves primarily through the drilling or identification of 395 well locations.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves: The standardized measure of discounted future net cash flows is not intended, nor should it be interpreted, to present the fair market value of the Company’s crude oil and natural gas reserves. An estimate of fair market value would take into consideration factors such as, but not limited to, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. At December 31, 2013, 2012 and 2011, the Company had a deferred hedging gain of $21.6 million, a deferred hedging gain of $74.8 million and a deferred hedging gain of $15 million, respectively, all of which are excluded from the calculation of standardized measure of future net cash flows.
Years ended December 31, (in thousands)	2013			2012			2011
Future gross revenues	$	19,509,305		$	17,735,363		$	18,196,229
Future production costs	6,136,709			5,715,248			5,823,395
Future development costs	1,896,602			1,892,600			1,539,072
Future income tax expense	3,209,697			2,809,411			3,326,382
Future net cash flows	8,266,297			7,318,104			7,507,380
Discount at 10% per annum	4,248,456			3,618,785			3,878,217
Standardized measure of discounted future net cash	$	4,017,841		$	3,699,319		$	3,629,163
flows relating to proved oil and gas reserves
The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
Years ended December 31, (in thousands)	2013			2012			2011
Balance at beginning of year	$	3,699,319		$	3,629,163		$	2,467,136
Revisions to reserves proved in prior years:
Net changes in prices, production costs and future development costs	566,838			(922,792		)	707,411
Net changes due to revisions in quantity estimates	(81,762		)	(383,755		)	(80,004		)
Development costs incurred, previously estimated	299,432			472,603			392,720
Accretion of discount	369,932			362,916			246,714
Changes in timing and other	(179,502		)	(317,244		)	(25,937		)
Total revisions	974,938			(788,272		)	1,240,904
New field discoveries and extensions, net of future production and development costs	376,326			1,025,419			755,977
Sales of oil and gas produced, net of production costs	(1,014,593		)	(812,781		)	(763,171		)
Purchases	4,690			189,755			232,768
Sales	(24,876		)	—			—
Net change in income taxes	2,037			456,035			(304,451		)
Net change in standardized measure of discounted future net cash flows	318,522			70,156			1,162,027
Balance at end of year	$	4,017,841		$	3,699,319		$	3,629,163

Industry_Segment_Information

Industry Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Industry Segment Information	'
	INDUSTRY 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). The accounting policies of the segments are the same as those described in Note 1, Summary of Significant Accounting Policies.
	Years ended December 31,(in thousands)	2013			2012			2011
	Operating revenues from continuing operations
	Oil and gas operations	$	1,205,312		$	1,089,230		$	838,160
	Natural gas distribution	533,338			451,589			534,953
	Total	$	1,738,650		$	1,540,819		$	1,373,113
	Operating income (loss) from continuing operations
	Oil and gas operations	$	257,963		$	369,765		$	308,561
	Natural gas distribution	93,768			93,216			86,216
	Eliminations and corporate expenses	(530		)	(1,067		)	(1,078		)
	Total	$	351,201		$	461,914		$	393,699
	Depreciation, depletion and amortization expense from continuing operations
	Oil and gas operations	$	453,474		$	343,183		$	213,841
	Natural gas distribution	43,907			42,270			39,916
	Total	$	497,381		$	385,453		$	253,757
	Interest expense
	Oil and gas operations	$	53,981		$	49,958		$	30,907
	Natural gas distribution	15,649			16,284			14,740
	Eliminations and other	(430		)	(700		)	(825		)
	Total	$	69,200		$	65,542		$	44,822
	Income tax expense (benefit) from continuing operations
	Oil and gas operations	$	71,290		$	115,090		$	100,700
	Natural gas distribution	34,687			30,244			26,670
	Other	(695		)	(800		)	(1,048		)
	Total	$	105,282		$	144,534		$	126,322
	Capital expenditures
	Oil and gas operations	$	1,104,745		$	1,291,211		$	1,115,452
	Natural gas distribution	88,769			71,869			73,984
	Total	$	1,193,514		$	1,363,080		$	1,189,436
	Identifiable assets
	Oil and gas operations	$	5,379,135		$	4,975,170		$	4,046,242
	Natural gas distribution	1,193,413			1,177,134			1,163,959
	Eliminations and other	49,664			23,586			27,215
	Total	$	6,622,212		$	6,175,890		$	5,237,416
	Property, plant and equipment, net
	Oil and gas operations	$	5,116,958		$	4,697,683		$	3,806,787
	Natural gas distribution	885,550			842,685			813,471
	Other	1,130			1,268			518
	Total	$	6,003,638		$	5,541,636		$	4,620,776

Schedule_II_Valuation_and_Qual

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2013
Valuation and Qualifying Accounts [Abstract]	'
Valuation and Qualifying Accounts	'
	VALUATION AND QUALIFYING ACCOUNTS
	Energen Corporation
	Years ended December 31, (in thousands)	2013			2012			2011
	ALLOWANCE FOR DOUBTFUL ACCOUNTS
	Balance at beginning of year	$	6,549		$	12,946		$	15,048
	Additions:
	Charged to income	2,244			1,415			4,269
	Recoveries and adjustments	(1,463		)	(1,262		)	(1,744		)
	Net additions	781			153			2,525
	Less uncollectible accounts written off	(1,636		)	(6,550		)	(4,627		)
	Balance at end of year	$	5,694		$	6,549		$	12,946
	Alabama Gas Corporation
	Years ended December 31, (in thousands)	2013			2012			2011
	ALLOWANCE FOR DOUBTFUL ACCOUNTS
	Balance at beginning of year	$	5,700		$	12,100		$	14,200
	Additions:
	Charged to income	2,243			1,409			4,202
	Recoveries and adjustments	(1,469		)	(1,263		)	(1,745		)
	Net additions	774			146			2,457
	Less uncollectible accounts written off	(1,474		)	(6,546		)	(4,557		)
	Balance at end of year	$	5,000		$	5,700		$	12,100

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Line Items]	'
Principles of Consolidation	'
	The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, principally Energen Resources Corporation and Alabama Gas Corporation (Alagasco), after elimination of all significant intercompany transactions in consolidation. Certain reclassifications have been made to conform the prior years’ financial statements to the current-year presentation.
Fair Value Measurements	'
	Fair Value Measurements
	The carrying values of cash and cash equivalents, accounts payable and receivable, derivative commodity instruments, pension and postretirement plan assets and liabilities and other current assets and liabilities approximate fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The fair value hierarchy that prioritizes the inputs used to measure fair value is defined as follows:
	Level 1 -	Unadjusted quoted prices in active markets for identical assets or liabilities;
	Level 2 -	Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;
	Level 3 -	Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.
	Derivative commodity instruments are OTC derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties’ valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.
	Pension and postretirement plan assets include mutual and comingled funds and limited partnerships. Plan assets were classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The determination and classification of fair value requires judgment and may affect the valuation of fair value assets and their placement within the fair value hierarchy. Level 1 and Level 2 fair values use market transactions and other market evidence whenever possible and consist primarily of equities, fixed income and mutual funds. Level 3 fair values used unobservable market prices primarily associated with certain alternative investments and a limited partnership.
Income Taxes	'
	Income Taxes
	The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change. The Company and its subsidiaries file a consolidated federal income tax return. Consolidated federal income taxes are charged to appropriate subsidiaries using the separate return method.
Accounts Receivable and Allowance for Doubtful Accounts	'
	Accounts Receivable and Allowance for Doubtful Accounts
	Trade accounts receivable are recorded at the invoiced amounts and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The Company determines the allowance based on historical experience and in consideration of current market conditions. Account balances are charged against the allowance when it is anticipated the receivable will not be recovered.
Cash and Cash Equivalents	'
	Cash and Cash Equivalents
	Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities within three months at the date of acquisition. Cash equivalents are stated at cost, which approximates fair value.
Short-term investments	'
	Short-term Investments
	All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short-term investments. As of December 31, 2013 and 2012, Energen had no short-term investments.
Earnings Per Share (EPS)	'
	Earnings Per Share (EPS)
	The Company’s basic earnings per share amounts have been computed based on the weighted average number of common shares outstanding. Diluted earnings per share amounts reflect the assumed issuance of common shares for all potentially dilutive securities.
Stock-Based Compensation	'
	Stock-Based Compensation
	The Company measures all share-based compensation awards at fair value at the date of grant and expenses the awards over the requisite vesting period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. The Company recognizes all stock-based compensation expense in the period of grant, subject to certain vesting requirements, for retirement eligible employees. The Company utilizes the long-form method of calculating the available pool of windfall tax benefit. For the years ended December 31, 2013, 2012 and 2011, the Company recognized an excess tax benefit of $3.1 million, $0.6 million and $1.0 million, respectively, related to its stock-based compensation.
Estimates	'
	Estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. The major estimates and assumptions identified by management include, but are not limited to, physical quantities of oil and gas reserves, periodic assessments of oil and gas properties for impairment, an assumption that regulatory accounting will continue as the applicable accounting standard for the Company’s regulated operations, the Company’s obligations under its employee pension and compensation plans, the valuation of derivative financial instruments, the allowance for doubtful accounts, tax contingency reserves, legal contingency reserves, asset retirement obligations, self insurance reserves and regulatory assets and liabilities. Due to the inherent uncertainty involved in making estimates, actual results reported in future periods may differ from the estimates.
Employee Benefit Plans	'
	Employee Benefit Plans
	Energen has two defined benefit non-contributory qualified pension plans. These plans cover substantially all employees. Pension benefits for the majority of the Company’s employees are based on years of service and final earnings; one plan is based on years of service and flat dollar amounts. The Company also has nonqualified supplemental pension plans covering certain officers of the Company. In addition to providing pension benefits, the Company provides certain postretirement health care and life insurance benefits for all employees hired prior to January 1, 2010. The Company continues to provide these benefits to certain non-salaried employees. These postretirement healthcare and life insurance benefits are available upon reaching normal retirement age while working for the Company. The projected unit credit actuarial method was used to determine the normal cost and actuarial liability.
	For retirement plans and other postretirement plans, certain financial assumptions are used in determining the Company’s projected benefit obligation. These assumptions are examined periodically by the Company, and any required changes are reflected in the subsequent determination of projected benefit obligations.
	Measurement: The Company calculates periodic expense for defined benefit pension plans and other postretirement benefit plans on an actuarial basis and the net funded status of benefit plans is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligation to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be provided through rates in the future. The Company measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position.
	Discount Rate: In selecting each discount rate, consideration was given to Moody’s Aa corporate bond rates, along with a yield curve applied to payments the Company expects to make out of its retirement plans. The yield curve is comprised of a broad base of Aa bonds with maturities between zero and thirty years. The discount rate for each plan was developed as the level equivalent rate that would produce the same present value as that using spot rates aligned with the projected benefit payments.
	Long-Term Rate of Return: The assumed rate of return on assets is the weighted average of expected long-term asset assumptions. The Company considered past performance and current expectations for assets held by the plans as well as the expected long-term allocation of plan assets.
	Other Significant Assumptions: The estimated weighted average rate of increase in the compensation level for pay related plans is another assumption used in calculation of the net periodic pension cost
Environmental Costs	'
	Environmental Costs
	Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated. As more fully described in Note 2, Regulatory Matters, and as currently approved, the ESR provides deferred treatment and recovery for extraordinary O&M expenses related to environmental response costs.
Investment, Policy	'
	Investment Strategy: The Company employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.
	The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals of the Company are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily.
	The Company seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.
Recently Issued Accounting Standards	'
	In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued Accounting Standard Update (ASU) No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 8, Financial Instruments.
	In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 16, Accumulated Other Comprehensive Income (Loss).
Oil and Gas Operations	'
Accounting Policies [Line Items]	'
Property and Related Depletion	'
	Property and Related Depletion: Energen Resources follows the successful efforts method of accounting for costs incurred in the exploration and development of oil, gas and natural gas liquid reserves. Lease acquisition costs are capitalized initially, and unproved properties are reviewed periodically to determine if there has been impairment of the carrying value, with any such impairment charged to exploration expense currently. All development costs are capitalized. Exploratory drilling costs are capitalized pending determination of proved reserves. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploration costs, including geological and geophysical costs, are expensed as incurred. Depreciation, depletion and amortization expense is determined on a field-by-field basis using the units-of-production method based on proved reserves. Anticipated abandonment and restoration costs are capitalized and depreciated using the units-of-production method based on proved developed reserves.
Operating Revenue and Gas Costs	'
	Operating Revenues: Energen Resources utilizes the sales method of accounting to recognize oil, gas and natural gas liquids production revenue. Under the sales method, revenues are based on actual sales volumes of commodities sold to purchasers. Over-production liabilities are established only when it is estimated that a property’s over-produced volumes exceed the net share of remaining reserves for such property. Energen Resources had no significant production imbalances at December 31, 2013 and 2012.
Derivative Commodity Instruments	'
	Derivative Commodity Instruments: Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Energen. All derivative transactions are included in operating activities on the consolidated statements of cash flows.
	The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of December 31, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights which may be exercised by the non-defaulting party in the event of an early termination due to a default.
	Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. The effective portion of the gain or loss on the derivative instrument was recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value 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 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. 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.
	Open mark-to-market gains (losses) on derivatives included in operating revenues were as follows:
	Years ended December 31, (in thousands)	2013			2012		2011
	Mark-to-market gain (loss) on derivatives	$	(47,832	)	$	58,750	$	(37,587	)
	All hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the nature of the risk being hedged.
Long-Lived Assets and Discontinued Operations	'
	Long-Lived Assets and Discontinued Operations: The Company reports gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for certain held-for-sale properties are reclassified and reported as discontinued operations for prior periods. 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.
Acquisitions	'
	Acquisitions: Energen Resources recognizes all acquisitions at fair value. Energen Resources estimates the fair value of the assets acquired and liabilities assumed as of the acquisition date, the date on which Energen Resources obtained control of the properties for all acquisitions that qualify as business combinations. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. Energen Resources uses a discounted cash flow model and makes market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs under the fair value hierarchy. Acquisition related costs are expensed as incurred in operations and maintenance (O&M) expense on the consolidated income statements.
Natural Gas Distribution	'
Accounting Policies [Line Items]	'
Inventories	'
	Inventories: Inventories, which consist primarily of gas stored underground, are stated at average cost. Liquified natural gas is stated at base cost.
Natural Gas Distribution | Alabama Gas Corporation	'
Accounting Policies [Line Items]	'
Operating Revenue and Gas Costs	'
	Operating Revenue and Gas Costs: Alagasco records natural gas distribution revenues in accordance with its tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material gas imbalances at December 31, 2013 and 2012.
Derivative Commodity Instruments	'
	Derivative Commodity Instruments: In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the Gas Supply Adjustment (GSA) rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability. All derivative commodity instruments in a gain position are valued on a discounted basis incorporating an estimate of performance risk specific to each related counterparty. Derivative commodity instruments in a loss position are valued on a discounted basis incorporating an estimate of performance risk specific to Alagasco.
Regulatory Accounting	'
	Regulatory Accounting: Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) with respect to rates, accounting and various other matters. Alagasco capitalizes or defers certain costs or revenues, based on the approvals received from the APSC, to be recovered from or refunded to customers in future periods. These costs or revenues are recorded as regulatory assets or liabilities.
Property and Related Depletion, and Utility Plant and Depreciation	'
	Utility Plant and Depreciation: Property, plant and equipment are stated at cost. The cost of utility plant includes an allowance for funds used during construction. Maintenance is charged for the cost of normal repairs and the renewal or replacement of an item of property which is less than a retirement unit. Gains and losses on all dispositions of land are recognized at time of disposal. When property which represents a retirement unit is replaced or removed, the cost of such property is credited to utility plant and is charged to the accumulated reserve for depreciation. The estimated net removal costs on certain gas distribution assets are charged through depreciation and recognized as a regulatory liability in accordance with regulatory accounting. Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of utility property at rates approved by the APSC. On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $16.3 million, $14.2 million, $22.2 million and $2.7 million for the years ended December 31, 2013, 2012 and 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $15.8 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $39.7 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a five year period beginning January 1, 2015. The total amount refundable to customers is subject to adjustments over the remaining five year period for charges made to the Enhanced Stability Reserve (ESR) and other APSC approved charges. The refunds as of December 2013 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates. Approved depreciation rates averaged approximately 3.1 percent, 3.2 percent and 3.1 percent in the years ended December 31, 2013, 2012 and 2011, respectively.
Taxes on Revenue	'
	Taxes on Revenues: The collection and payment of revenue taxes such as utility license taxes and fees, franchise fees and taxes imposed by other governmental authorities are reported on a gross basis. These amounts are included in taxes, other than income taxes on the consolidated statements of income as follows:
	Years ended December 31, (in thousands)	2013			2012		2011
	Taxes on revenues	$	25,870		$	21,479	$	25,268
	The collection and payment of utility gross receipts tax is presented on a net basis.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [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 during the year:
	Years ended December 31, (in thousands)	2013			2012			2011
	Capitalized exploratory well costs at beginning of period	$	79,791		$	70,437		$	21,438
	Additions pending determination of proved reserves	421,599			406,226			178,005
	Reclassifications due to determination of proved reserves	(442,909		)	(396,872		)	(129,006		)
	Exploratory well costs charged to expense	(881		)	—			—
	Capitalized exploratory well costs at end of period	$	57,600		$	79,791		$	70,437
	The following table sets forth capitalized exploratory wells costs at year end and includes amounts capitalized for a period greater than one year:
	Years ended December 31, (in thousands)	2013			2012			2011
	Exploratory wells in progress	$	14,794		$	77,693		$	70,437
	Capitalized exploratory well costs for a period of one year or less	42,481			—			—
	Capitalized exploratory well costs for a period greater than one year	1,206			2,098			—
	Total capitalized exploratory well costs	$	58,481		$	79,791		$	70,437
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance	'
	Open mark-to-market gains (losses) on derivatives included in operating revenues were as follows:
	Years ended December 31, (in thousands)	2013			2012			2011
	Mark-to-market gain (loss) on derivatives	$	(47,832	)	$	58,750		$	(37,587	)
Schedule of taxes other than income taxes	'
	The collection and payment of revenue taxes such as utility license taxes and fees, franchise fees and taxes imposed by other governmental authorities are reported on a gross basis. These amounts are included in taxes, other than income taxes on the consolidated statements of income as follows:
	Years ended December 31, (in thousands)	2013			2012			2011
	Taxes on revenues	$	25,870		$	21,479		$	25,268

LongTerm_Debt_and_Notes_Payabl1

Long-Term Debt and Notes Payable (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Instrument [Line Items]	'
Schedule of long-term debt	'
	Long-term debt consisted of the following:
	(in thousands)	December 31, 2013			December 31, 2012
	Energen Corporation:
	Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 24, 2017 to February 15, 2028	$	154,000		$	154,000
	5% Notes	—			50,000
	4.625% Notes, due September 1, 2021	400,000			400,000
	Senior Term Loans, (floating rate interest LIBOR plus 1.625%; 1.792% at December 31, 2013), due March 31, 2014 to December 17, 2017	600,000			—
	Senior Term Loans, (floating rate interest LIBOR plus 1.375%)	—			300,000
	Alabama Gas Corporation:
	5.20% Notes, due January 15, 2020	40,000			40,000
	5.70% Notes, due January 15, 2035	34,923			35,028
	5.368% Notes, due December 1, 2015	80,000			80,000
	5.90% Notes, due January 15, 2037	45,000			45,000
	3.86% Notes, due December 21, 2021	50,000			50,000
	Total	1,403,923			1,154,028
	Less amounts due within one year	60,000			50,000
	Less unamortized debt discount	459			500
	Total	$	1,343,464		$	1,103,528
Schedule of aggregate maturities of long-term debt	'
	The aggregate maturities of Energen’s long-term debt for the next five years are as follows:
	Years ending December 31, (in thousands)
	2014	2015	2016	2017	2018
	$60,000	$140,000	$60,000	$439,000	—
Schedule of credit facilities	'
	he following is a summary of information relating to the credit facilities:
	(in thousands)	December 31, 2013			December 31, 2012
	Energen outstanding	$	489,000		$	566,000
	Alagasco outstanding	50,000			77,000
	Notes payable to banks	539,000			643,000
	Available for borrowings	811,000			707,000
	Total	$	1,350,000		$	1,350,000
	Energen maximum amount outstanding at any month-end	$	901,000		$	643,000
	Energen average daily amount outstanding	$	804,895		$	331,068
	Energen weighted average interest rates based on:
	Average daily amount outstanding	1.38		%	1.82		%
	Amount outstanding at year-end	1.32		%	1.35		%
	Alagasco maximum amount outstanding at any month-end	$	75,000		$	77,000
	Alagasco average daily amount outstanding	$	35,027		$	21,254
	Alagasco weighted average interest rates based on:
	Average daily amount outstanding	1.12		%	1.44		%
	Amount outstanding at year-end	1.26		%	1.11		%
Alabama Gas Corporation	'
Debt Instrument [Line Items]	'
Schedule of aggregate maturities of long-term debt	'
	he aggregate maturities of Alagasco’s long-term debt for the next five years are as follows:
	Years ending December 31, (in thousands)
	2014	2015	2016	2017	2018
	—	$80,000	—	—	—

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Line Items]	'
Schedule of components of Income taxes	'
	The components of Energen’s income taxes consisted of the following:
	Years ended December 31, (in thousands)	2013			2012			2011
	Taxes estimated to be payable currently:
	Federal	$	23,342		$	16,295		$	11,595
	State	2,516			3,125			5,065
	Total current	25,858			19,420			16,660
	Taxes deferred:
	Federal	85,950			119,053			125,622
	State	(2,300		)	5,346			3,419
	Total deferred	83,650			124,399			129,041
	Total income tax expense	$	109,508		$	143,819		$	145,701
Schedule of Components of Income Tax Expense (Benefit), Continuing and Discontinued Operations	'
	The components of Energen’s income taxes consisted of the following:
	Years ended December 31, (in thousands)	2013			2012			2011
	Income tax expense from continuing operations	$	105,282		$	144,534		$	126,322
	Income tax expense (benefit) from discontinued operations	2,215			(715		)	19,379
	Income tax expense from gain on disposal of discontinued operations	2,011			—			—
	Total income tax expense	$	109,508		$	143,819		$	145,701
Schedule of deferred tax assets and liabilities	'
	Temporary differences and carryforwards which gave rise to Energen’s deferred tax assets and liabilities were as follows:
	(in thousands)	December 31, 2013						December 31, 2012
		Current			Noncurrent			Current			Noncurrent
	Deferred tax assets:
	Unbilled and deferred revenue	$	12,547		$	—		$	10,137		$	—
	Allowance for doubtful accounts	2,066			—			2,408			—
	Insurance and other accruals	4,851			—			3,821			—
	Compensation accruals	15,405			—			13,116			—
	Inventories	1,260			—			1,664			—
	Other comprehensive income	—			15,350			—			19,158
	Gas supply adjustment related accruals	698			—			969			—
	Derivative instruments	10,769			—			—			—
	State net operating losses and other carryforwards	—			4,577			—			3,577
	Other	1,219			1			1,340			25
	Total deferred tax assets	48,815			19,928			33,455			22,760
	Valuation allowance	(299		)	(2,674		)	(268		)	(2,793		)
	Total deferred tax assets	48,516			17,254			33,187			19,967
	Deferred tax liabilities:
	Depreciation and basis differences	—			1,008,026			—			898,625
	Pension and other costs	—			15,379			—			20,143
	Derivative instruments	—			2,048			4,272			3,162
	Other comprehensive income	5,540			—			18,133			—
	Other	1,677			5,046			2,262			3,638
	Total deferred tax liabilities	7,217			1,030,499			24,667			925,568
	Net deferred tax assets (liabilities)	$	41,299		$	(1,013,245	)	$	8,520		$	(905,601	)
Schedule of effective income tax rate reconciliation	'
	Total income tax expense from continuing operations for the Company differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:
	Years ended December 31, (in thousands)	2013			2012			2011
	Income tax expense at statutory federal income tax rate	$	104,450		$	139,914		$	122,719
	Increase (decrease) resulting from:
	State income taxes, net of federal income tax benefit	3,799			4,755			8,341
	Impact of state law changes	(1,966		)	—			(2,059		)
	Qualified Section 199 production activities deduction	—			(61		)	(495		)
	401(k) stock dividend deduction	(449		)	(514		)	(532		)
	Other, net	(552		)	440			(1,652		)
	Total income tax expense	$	105,282		$	144,534		$	126,322
	Effective income tax rate (%)	35.28			36.16			36.03
Schedule of reconciliation of unrecognized tax benefits	'
	A reconciliation of Energen’s beginning and ending amount of unrecognized tax benefits is as follows:
	(in thousands)
	Balance as of December 31, 2010	$	24,590
	Additions based on tax positions related to the current year	3,644
	Additions for tax positions of prior years	2,324
	Reductions for tax positions of prior years	(39		)
	Lapse of statute of limitations	(1,482		)
	Settlements	(18,444		)
	Balance as of December 31, 2011	10,593
	Additions based on tax positions related to the current year	3,731
	Additions for tax positions of prior years	269
	Reductions for tax positions of prior years	(446		)
	Lapse of statute of limitations	(1,592		)
	Balance as of December 31, 2012	12,555
	Additions based on tax positions related to the current year	4,546
	Additions for tax positions of prior years	366
	Reductions for tax positions of prior years	(46		)
	Lapse of statute of limitations	(1,435		)
	Balance as of December 31, 2013	$	15,986
Alabama Gas Corporation	'
Income Tax Disclosure [Line Items]	'
Schedule of components of Income taxes	'
	The components of Alagasco’s income taxes consisted of the following:
	Years ended December 31, (in thousands)	2013			2012			2011
	Taxes estimated to be payable currently:
	Federal	$	17,495		$	18,227		$	(1,280	)
	State	2,192			739			(108		)
	Total current	19,687			18,966			(1,388		)
	Taxes deferred:
	Federal	13,252			9,066			24,938
	State	1,748			2,212			3,120
	Total deferred	15,000			11,278			28,058
	Total income tax expense	$	34,687		$	30,244		$	26,670
Schedule of deferred tax assets and liabilities	'
	Temporary differences and carryforwards which gave rise to Alagasco’s deferred tax assets and liabilities were as follows:
	(in thousands)	December 31, 2013						December 31, 2012
		Current			Noncurrent			Current			Noncurrent
	Deferred tax assets:
	Unbilled and deferred revenue	$	12,547		$	—		$	10,137		$	—
	Allowance for doubtful accounts	1,815			—			2,155			—
	Insurance accruals	1,769			—			1,856			—
	Compensation accruals	2,480			—			2,645			—
	Inventories	1,260			—			1,664			—
	Gas supply adjustment related accruals	698			—			969			—
	Other	984			1			774			2
	Total deferred tax assets	21,553			1			20,200			2
	Deferred tax liabilities:
	Depreciation and basis differences	—			186,601			—			167,329
	Pension and other costs	—			19,031			—			22,054
	Other	1,504			—			1,401			—
	Total deferred tax liabilities	1,504			205,632			1,401			189,383
	Net deferred tax assets (liabilities)	$	20,049		$	(205,631	)	$	18,799		$	(189,381	)
Schedule of effective income tax rate reconciliation	'
	Total income tax expense for Alagasco differed from the amount which would have been provided by applying the statutory federal income tax rate of 35 percent to earnings before taxes as illustrated below:
	Years ended December 31, (in thousands)	2013			2012			2011
	Income tax expense at statutory federal income tax rate	$	32,230		$	27,876		$	25,645
	Increase (decrease) resulting from:
	State income taxes, net of federal income tax benefit	2,588			2,238			2,059
	Reversal of tax reserves from audit settlements, net	—			—			(1,365		)
	Other, net	(131		)	130			331
	Total income tax expense	$	34,687		$	30,244		$	26,670
	Effective income tax rate (%)	37.67			37.97			36.4
Schedule of reconciliation of unrecognized tax benefits	'
	A reconciliation of Alagasco’s beginning and ending amount of unrecognized tax benefits is as follows:
	(in thousands)
	Balance as of December 31, 2010	$	18,941
	Additions based on tax positions related to the current year	13
	Additions for tax positions of prior years	1
	Reductions for tax positions of prior years (lapse of statute of limitations)	(409		)
	Settlements	(18,444		)
	Balance as of December 31, 2011	102
	Additions based on tax positions related to the current year	62
	Additions for tax positions of prior years	201
	Reductions for tax positions of prior years (lapse of statute of limitations)	(58		)
	Balance as of December 31, 2012	307
	Reductions for tax positions of prior years (lapse of statute of limitations)	(31		)
	Balance as of December 31, 2013	$	276

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]	'
Schedule of benefit obligations	'
	Benefit Obligations: The following table sets forth the combined funded status of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in the Company’s consolidated financial statements:
	As of December 31, (in thousands)	2013				2012			2013				2012
		Pension							Postretirement Benefits
	Accumulated benefit obligation	$	253,030			$	269,101
	Benefit obligation:
	Balance at beginning of period	$	323,540			$	250,619		$	85,785			$	88,064
	Service cost	14,173				10,527			1,694				1,853
	Interest cost	11,239				10,801			3,504				4,248
	Actuarial (gain) loss	(28,339		)		65,048			(21,681		)		(5,413		)
	Curtailment gain	(4,223		)		—			(1,255		)		—
	Retiree drug subsidy program	—				—			261				360
	Benefits paid	(23,036		)		(13,455		)	(4,726		)		(3,327		)
	Balance at end of period	$	293,354			$	323,540		$	63,582			$	85,785
	Plan assets:
	Fair value of plan assets at beginning of period	$	209,424			$	195,659		$	87,189			$	78,121
	Actual return on plan assets	22,977				24,841			14,892				8,778
	Employer contributions	10,169				2,379			1,578				3,617
	Benefits paid	(23,036		)		(13,455		)	(4,726		)		(3,327		)
	Fair value of plan assets at end of period	$	219,534			$	209,424		$	98,933			$	87,189
	Funded status of plans	$	(73,820	)		$	(114,116	)	$	35,351			$	1,404
	Noncurrent assets	$	—			$	—		$	35,351			$	1,404
	Current liabilities	(6,145		)		(3,834		)	—				—
	Noncurrent liabilities	(67,675		)		(110,282		)	—				—
	Net asset (liability) recognized	$	(73,820	)		$	(114,116	)	$	35,351			$	1,404
	Amounts recognized to accumulated other comprehensive income:
	Prior service costs, net of taxes	$	323			$	528		$	—			$	—
	Net actuarial (gain) loss, net of taxes	37,479				52,472			(5,584		)		(715		)
	Transition obligation, net of taxes	—				—			27				222
	Total accumulated other comprehensive income (loss)	$	37,802			$	53,000		$	(5,557	)		$	(493	)
Schedule of allocation of plan assets	'
	The Company’s weighted average plan asset allocations by asset category were as follows:
		Pension						Postretirement Benefits
	As of December 31,	Target		2013		2012		Target		2013		2012
	Asset category:
	Equity securities	41	%	34	%	41	%	60	%	61	%	60	%
	Debt securities	38	%	28	%	38	%	40	%	39	%	40	%
	Other	21	%	38	%	21	%	—	%	—	%	—	%
	Total	100	%	100	%	100	%	100	%	100	%	100	%
Schedule of net periodic benefit cost	'
	The components of net periodic benefit cost were as follows:
	Years ended December 31, (in thousands)	2013			2012			2011
	Pension Plans
	Components of net periodic benefit cost:
	Service cost	$	14,173		$	10,527		$	9,173
	Interest cost	11,239			10,801			10,960
	Expected long-term return on assets	(14,731		)	(14,093		)	(15,471		)
	Prior service cost amortization	490			517			496
	Actuarial loss amortization	13,979			8,603			6,435
	Termination benefit charge	—			—			414
	Settlement charge	1,373			—			—
	Net periodic expense	$	26,523		$	16,355		$	12,007
	Postretirement Benefit Plans
	Components of net periodic benefit cost:
	Service cost	$	1,694		$	1,853		$	1,769
	Interest cost	3,504			4,248			4,443
	Expected long-term return on assets	(5,024		)	(4,438		)	(4,418		)
	Actuarial (gain) loss amortization	(120		)	37			—
	Transition obligation amortization	1,296			1,917			1,917
	Curtailment gain	(1,229		)	—			—
	Net periodic expense	$	121		$	3,617		$	3,711
Schedule of other changes in plan assets and projected benefit obligations recognized in other comprehensive income	'
	Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows:
	Years ended December 31, (in thousands)	2013			2012			2011
	Pension Plans
	Net actuarial (gain) loss experienced during the year	$	(14,138	)	$	28,748		$	14,312
	Net actuarial loss recognized as expense	(8,934		)	(4,908		)	(3,755		)
	Prior service cost recognized as expense	(311		)	(340		)	(298		)
	Total recognized in other comprehensive income (loss)	(23,383		)	23,500			10,259
	Postretirement Benefit Plans
	Net actuarial (gain) loss experienced during the year	$	(8,057	)	$	(1,787	)	$	2,111
	Net actuarial gain recognized as expense	550			—			—
	Transition obligation recognized as expense	(283		)	(294		)	(286		)
	Total recognized in other comprehensive income (loss)	$	(7,790	)	$	(2,081	)	$	1,825
Schedule of estimated amount to be amortized from accumulated other comprehensive income	'
	Estimated amounts to be amortized from accumulated other comprehensive income into pension cost during 2014 are as follows:
	(in thousands)
	Amortization of prior service cost	$	314
	Amortization of net actuarial loss	$	5,422
	Estimated amounts to be amortized from accumulated other comprehensive income into postretirement benefit cost during 2014 are as follows:
	(in thousands)
	Amortization of net transition obligation	$	42
	Amortization of net actuarial gain	$	(593	)
Schedule of weighted average rate assumptions	'
	The weighted average rate assumptions to determine net periodic benefit costs were as follows:
	Years ended December 31,	2013		2012		2011
	Pension Plans
	Discount rate	3.63	%	4.52	%	4.89	%
	Expected long-term return on plan assets	7	%	7	%	7.25	%
	Rate of compensation increase for pay-related plans	3.71	%	3.59	%	3.75	%
	Postretirement Benefit Plans
	Discount rate	4.26	%	4.95	%	5.45	%
	Expected long-term return on plan assets	7	%	7	%	7.25	%
	Rate of compensation increase	3.7	%	3.55	%	3.61	%
	The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:
	Years ended December 31,	2013		2012
	Pension Plans
	Discount rate	4.31	%	3.47	%
	Rate of compensation increase for pay-related plans	3.63	%	3.71	%
	Postretirement Benefit Plans
	Discount rate	4.95	%	4.15	%
	Rate of compensation increase for pay-related plans	3.6	%	3.7	%
Schedule of assumed post-65 health care cost rend rates	'
	The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:
	As of December 31,	2013		2012
	Health care cost trend rate assumed for next year	6.5	%	6.75	%
	Rate to which the cost trend rate is assumed to decline	5	%	5	%
	Year that rate reaches ultimate rate	2020		2020
Schedule of effect of 1 percentage point change in assumed health care cost trend rates	'
	Assumed health care cost trend rates used in determining the accumulated postretirement benefit obligation have an effect on the amounts reported. For example, revising the weighted average health care cost trend rate by 1 percentage point would have the following effects:
	(in thousands)
		1-Percentage Point Decrease			1-Percentage Point Increase
	Effect on total of service and interest cost	$	(280	)	$	336
	Effect on net postretirement benefit obligation	$	(764	)	$	759
Schedule of expected benefit payments	'
	The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:
	(in thousands)	Pension Benefits	Postretirement Benefits	Postretirement Benefits – Prescription Drug Subsidy
	2014	$66,816	$4,156	($212)
	2015	$16,572	$4,219	($218)
	2016	$18,174	$4,286	($224)
	2017	$22,167	$4,362	($227)
	2018	$28,374	$4,426	($231)
	2019-2023	$134,584	$22,319	($1,202)
Pension Plans	'
Defined Benefit Plan Disclosure [Line Items]	'
Schedule of allocation of plan assets	'
	Plan assets included in the funded status of the pension plans were as follows:
		December 31, 2013
	(in thousands)	Level 1			Level 2			Level 3			Total
	United States equities	$	34,117		$	8,080		$	—		$	42,197
	Global equities	20,153			13,256			—			33,409
	Fixed income	—			61,121			—			61,121
	Alternative investments	—			37,292			—			37,292
	Cash and cash equivalents	5,970			39,545			—			45,515
	Total	$	60,240		$	159,294		$	—		$	219,534
		December 31, 2012
	(in thousands)	Level 1			Level 2			Level 3			Total
	United States equities	$	41,907		$	9,072		$	—		$	50,979
	Global equities	23,782			10,697			—			34,479
	Fixed income	—			78,806			—			78,806
	Alternative investments	—			27,659			14,500			42,159
	Cash and cash equivalents	—			3,001			—			3,001
	Total	$	65,689		$	129,235		$	14,500		$	209,424
Schedule of reconciliation of plan assets in Level 3 of fair value hierarchy	'
	The following is a reconciliation of plan assets in Level 3 of the fair value hierarchy:
	Years ended December 31, (in thousands)	2013			2012			2011
	Balance at beginning of period	$	14,500		$	17,399		$	26,841
	Unrealized gains (losses)	—			992			(752		)
	Unrealized gains relating to instruments held at the reporting date	—			242			635
	Settlements	—			(4,948		)	(9,604		)
	Purchases	—			815			279
	Transfer out of Level 3	(14,500		)	—			—
	Balance at end of period	$	—		$	14,500		$	17,399
Postretirement Benefit Plans	'
Defined Benefit Plan Disclosure [Line Items]	'
Schedule of allocation of plan assets	'
	Plan assets included in the funded status of the postretirement benefit plans were as follows:
		December 31, 2013
	(in thousands)	Level 1			Level 2			Total
	United States equities	$	43,054		$	—		$	43,054
	Global equities	17,048			—			17,048
	Fixed income	—			38,831			38,831
	Total	$	60,102		$	38,831		$	98,933
		December 31, 2012
	(in thousands)	Level 1			Level 2			Total
	United States equities	$	37,482		$	—		$	37,482
	Global equities	15,049			—			15,049
	Fixed income	—			34,658			34,658
	Total	$	52,531		$	34,658		$	87,189
Nonqualified Supplemental Retirement Plans	'
Defined Benefit Plan Disclosure [Line Items]	'
Schedule of allocation of plan assets	'
	Other investment assets designated for payment of the nonqualified supplemental retirement plans were as follows:
		December 31, 2013
	(in thousands)	Level 1			Level 2			Level 3			Total
	Insurance contracts	$	—		$	14,805		$	—		$	14,805
	United States equities	5,579			—			—			5,579
	Global equities	2,338			—			—			2,338
	Fixed income	—			11,039			—			11,039
	Total	$	7,917		$	25,844		$	—		$	33,761
		December 31, 2012
	(in thousands)	Level 1			Level 2			Level 3			Total
	Insurance contracts	$	—		$	7,399		$	5,600		$	12,999
	United States equities	4,741			—			—			4,741
	Global equities	2,109			—			—			2,109
	Fixed income	—			10,219			—			10,219
	Total	$	6,850		$	17,618		$	5,600		$	30,068
Schedule of reconciliation of plan assets in Level 3 of fair value hierarchy	'
	The following is a reconciliation of insurance contracts in Level 3 of the fair value hierarchy:
	Years ended December 31, (in thousands)	2013			2012			2011
	Balance at beginning of period	$	5,600		$	5,332		$	5,069
	Unrealized gains relating to instruments held at the reporting date	—			268			263
	Transfer out of Level 3	(5,600		)	—			—
	Balance at end of period	$	—		$	5,600		$	5,332

Common_Stock_Plans_Tables

Common Stock Plans (Tables)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Schedule of performance share award activity	'
	No performance share awards were granted in 2012 or 2011. A summary of performance share award activity as of December 31, 2013, and transactions during the year ended December 31, 2013 is presented below:
		Stock Incentive Plan
		Shares		Weighted
				Average Price
	Nonvested at December 31, 2012	—		$	—
	Granted (two-year vesting period)	86,221		61.14
	Granted (three-year vesting period)	82,606		62.96
	Forfeited	(8,008	)	60.03
	Nonvested at December 31, 2013	160,819		$	62.13
Schedule of stock option activity and transactions	'
	A summary of stock option activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 are presented below:
		Stock Incentive Plan
		Shares		Weighted Average Exercise Price
	Outstanding at December 31, 2010	1,276,043		$	40.16
	Granted	293,978		54.99
	Exercised	(227,405	)	32.33
	Forfeited	(4,375	)	35.35
	Outstanding at December 31, 2011	1,338,241		44.77
	Granted	371,040		54.11
	Exercised	(58,471	)	24.55
	Forfeited	(2,335	)	46.45
	Outstanding at December 31, 2012	1,648,475		47.58
	Granted	137,762		49.22
	Exercised	(590,119	)	40.92
	Forfeited	(5,074	)	51.85
	Outstanding at December 31, 2013	1,191,044		$	51.06
	Exercisable at December 31, 2011	677,753		$	43.72
	Exercisable at December 31, 2012	987,733		$	43.75
	Exercisable at December 31, 2013	713,445		$	49.8
	Remaining reserved for issuance at December 31, 2013	2,921,392		—
Schedule of stock options valuation assumptions	'
	The Company uses the Black-Scholes pricing model to calculate the fair values of the options awarded. For purposes of this valuation the following assumptions were used to derive the fair values:
	Grant date	10/15/13	1/24/13		1/25/12		1/26/11
	Awards granted	3,686	134,076		371,040		293,978
	Fair market value of stock option at grant	$30.53	$16.66		$18.79		$19.65
	Expected life of award	5.8 years	5.8 years		5.8 years		5.8 years
	Risk-free interest rate	1.79%	1.01	%	1.07	%	2.45	%
	Annualized volatility rate	40.60%	40.3	%	39.6	%	37.8	%
	Dividend yield	0.70%	1.2	%	1	%	1	%
Schedule of outstanding stock options by range of exercise prices	'
	The following table summarizes options outstanding as of December 31, 2013:
	Stock Incentive Plan
	Range of Exercise Prices	Shares	Weighted Average Remaining Contractual Life
	$46.45	59,330	3.00 years
	$60.56	99,965	4.00 years
	$29.79	78,222	5.00 years
	$46.69	203,469	6.00 years
	$54.99	266,166	7.00 years
	$54.11	349,754	8.00 years
	$48.36	130,452	9.00 years
	$80.48	3,686	9.83 years
	$29.79-$80.48	1,191,044	6.77 years
Schedule of restricted stock activity and transactions	'
	A summary of restricted stock activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 is presented below:
		Stock Incentive Plan
		Shares		Weighted Average Price
	Nonvested at December 31, 2010	24,150		$	35.49
	Vested	(14,875	)	30.81
	Nonvested at December 31, 2011	9,275		42.99
	Granted	11,115		45.24
	Vested	(9,275	)	42.97
	Nonvested at December 31, 2012	11,115		45.24
	Granted	52,650		52.34
	Forfeited	(1,247	)	48.36
	Nonvested at December 31, 2013	62,518		$	51.16
Schedule of Share-based Compensation, Stock Appreciation Rights Award Activity [Table Text Block]	'
	A summary of stock appreciation rights activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 are presented below:
		Stock Appreciation Rights Plan
		Shares		Weighted Average Exercise Price
	Outstanding at December 31, 2010	656,340		$	38.3
	Granted	189,984		54.99
	Exercised/forfeited	(69,106	)	41.21
	Outstanding at December 31, 2011	777,218		42
	Exercised/forfeited	(124,188	)	30.9
	Outstanding at December 31, 2012	653,030		44.14
	Granted	88,000		48.36
	Exercised/forfeited	(363,653	)	39.66
	Outstanding at December 31, 2013	377,377		$	49.48
Schedule of stock appreciation rights valuation assumptions	'
	For purposes of this valuation the following assumptions were used to derive the fair values as of December 31, 2013:
	Grant date	1/24/13	1/24/13	1/26/11	1/26/11	1/27/10
			(modified)		(modified)
	Awards granted	87,069	931	182,199	7,785	171,749
	Fair market value of award	$34.66	$27.89	$27.07	$24.21	$30.10
	Expected life of award	5.6 years	2.5 years	3.6 years	2.5 years	3.0 years
	Risk-free interest rate	2.04%	0.56%	1.06%	0.56%	0.80%
	Annualized volatility rate	40.60%	40.60%	40.60%	40.60%	40.60%
	Dividend yield	0.80%	0.80%	0.80%	0.80%	0.80%
	Grant date	2/13-16/2009	1/28/09	2/4/08	2/1/07
	Awards granted	3,292	305,257	67,093	85,906
	Fair market value of award	$39.87	$41.18	$18.50	$27.03
	Expected life of award	2.5 years	2.5 years	2.0 years	1.5 years
	Risk-free interest rate	0.58%	0.58%	0.39%	0.23%
	Annualized volatility rate	40.60%	40.60%	40.60%	40.60%
	Dividend yield	0.80%	0.80%	0.80%	0.80%
Petrotech Incentive Plan	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Schedule of incentive units activity	'
	A summary of Petrotech unit activity as of December 31, 2013, and transactions during the years ended December 31, 2013, 2012 and 2011 are presented below:
			Petrotech Incentive Plan
			Shares
	Outstanding at December 31, 2010		8,205
	Granted (three-year vesting period)		6,314
	Paid		(1,914	)
	Forfeited		(1,544	)
	Outstanding at December 31, 2011		11,061
	Granted (three-year vesting period)		102,349
	Granted (two-year vesting period)		3,768
	Granted (18 month vesting period)		40,822
	Paid		(3,281	)
	Forfeited		(13,476	)
	Outstanding at December 31, 2012		141,243
	Granted (three-year vesting period)		92,418
	Granted (17 month vesting period)		2,952
	Paid		(36,792	)
	Forfeited		(26,529	)
	Outstanding at December 31, 2013		173,292

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Operating Leased Assets [Line Items]	'
Schedule of minimum future rental payments	'
	Minimum future rental payments required after 2013 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
	Years Ending December 31, (in thousands)
	2014	2015	2016	2017	2018	2019 and thereafter
	$5,270	$4,940	$4,391	$3,980	$2,409	$10,637
Alabama Gas Corporation	'
Operating Leased Assets [Line Items]	'
Schedule of minimum future rental payments	'
	Minimum future rental payments required after 2013 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:
	Years Ending December 31, (in thousands)
	2014	2015	2016	2017	2018	2019 and thereafter
	$4,291	$4,062	$3,994	$3,979	$2,409	$10,637

Financial_Instruments_and_Risk1

Financial Instruments and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Schedule of changes in 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, 2011	$	421
	Provision	49
	Allowance for credit losses as of December 31, 2012	470
	Provision	(47		)
	Allowance for credit losses as of December 31, 2013	$	423
Schedule of fair values of commodity contracts by business segment on balance sheet	'
	The following table details the fair values of commodity contracts by business segment on the balance sheets:
	(in thousands)	December 31, 2013
		Oil and Gas Operations			Natural Gas Distribution		Total
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	36,224			—		36,224
	Long-term asset derivative instruments	7,992			—		7,992
	Total derivative assets	44,216			—		44,216
	Accounts receivable	(18,761	)	*	—		(18,761	)
	Long-term asset derivative instruments	(2,553	)	*	—		(2,553	)
	Accounts payable	(30,302	)		—		(30,302	)
	Total derivative liabilities	(51,616	)		—		(51,616	)
	Total derivatives not designated	(7,400	)		—		(7,400	)
	(in thousands)	December 31, 2012
		Oil and Gas Operations				Natural Gas Distribution			Total
	Derivative assets or (liabilities) designated as hedging instruments
	Accounts receivable	$	87,514			$	—		$	87,514
	Long-term asset derivative instruments	37,954				—			37,954
	Total derivative assets	125,468				—			125,468
	Accounts receivable	(37,326		)	*	—			(37,326		)
	Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
	Long-term liability derivative instruments	(8,726		)		—			(8,726		)
	Total derivative liabilities	(52,862		)		—			(52,862		)
	Total derivatives designated	72,606				—			72,606
	Derivative assets or (liabilities) not designated as hedging instruments
	Accounts receivable	14,604				—			14,604
	Long-term asset derivative instruments	9,433				—			9,433
	Total derivative assets	24,037				—			24,037
	Accounts payable	—				(2,593		)	(2,593		)
	Long-term liability derivative instruments	(874		)		—			(874		)
	Total derivative liabilities	(874		)		(2,593		)	(3,467		)
	Total derivatives not designated	23,163				(2,593		)	20,570
	Total derivatives	$	95,769			$	(2,593	)	$	93,176
	* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.
Schedule of cash flow hedging relationships on financial statements	'
	The following table details the effect of derivative commodity instruments designated as hedging instruments on the financial statements:
	Years ended December 31, (in thousands)	Location on Income Statement	2013			2012			2011
	Net gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($6,660), $40,720 and $41,399	—	$	(10,866	)	$	66,438		$	67,547
	Gain reclassified from accumulated OCI into	Operating revenues	$	34,293		$	52,694		$	26,326
	income (effective portion)
	Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	835		$	(5,340	)	$	(2,767	)
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:
	Years ended December 31, (in thousands)	Location on Income Statement	2013			2012			2011
	Gain (loss) recognized in income on derivative	Operating revenues	$	(73,980	)	$	61,841		$	(37,587	)
Schedule of hedging transactions	'
	As of December 31, 2013, Energen Resources entered into the following transactions for 2014 and subsequent years:
	Production Period	Total Hedged Volumes		Average Contract	Description
				Price
	Natural Gas
	2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
		31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
		9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
	2015	6	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
	Oil
	2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
	2015	5,760	MBbl	$88.85 Bbl	NYMEX 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:
		December 31, 2013
	(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	)
		December 31, 2012
	(in thousands)	Level 2*			Level 3*			Total
	Current assets	$	(3,629	)	$	68,421		$	64,792
	Noncurrent assets	18,899			21,678			40,577
	Current liabilities	(2,593		)	—			(2,593		)
	Noncurrent liabilities	(8,520		)	(1,080		)	(9,600		)
	Net derivative asset	$	4,157		$	89,019		$	93,176
	* Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.
Schedule of changes in fair value of derivative instruments classified as level 3	'
	The table below sets forth a summary of changes in the fair value of the Company’s Level 3 derivative commodity instruments as follows:
	Years ended December 31, (in thousands)	2013			2012			2011
	Balance at beginning of period	$	89,019		$	65,801		$	42,755
	Realized gains	55,210			63,720			52,716
	Unrealized gains (losses) relating to instruments held at the reporting date*	(71,367		)	22,160			23,980
	Settlements during period	(54,573		)	(62,662		)	(53,650		)
	Balance at end of period	$	18,289		$	89,019		$	65,801
	*Includes $7.6 million in mark-to-market losses, $19.9 million in mark-to-market gains and $5.2 million in mark-to-market losses for the years ended December 31, 2013, 2012 and 2011, respectively.
Schedule of level three fair value measurements of derivative commodity instruments	'
	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 December 31, 2013			Valuation Technique*	Unobservable Input*	Range
	Natural Gas Basis - San Juan
	2014	$	18,159		Discounted Cash Flow	Forward Basis	($0.17 - $0.20) Mcf
	2015	$	1,056		Discounted Cash Flow	Forward Basis	($0.26) Mcf
	Natural Gas Basis - Permian
	2014	$	(1,948	)	Discounted Cash Flow	Forward Basis	($0.18 - $0.20) Mcf
	Natural Gas Liquids
	2014	$	1,022		Discounted Cash Flow	Forward Price	$0.80 - $0.81 Gal
	*Discounted cash flow represents an income approach in calculating fair value including the referenced unobservable input and a discount reflecting credit quality of the counterparty.
Offsetting Assets and Liabilities	'
	The tables below set forth information about the offsetting of derivative assets and liabilities as follows:
		31-Dec-13
											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
		31-Dec-12
											Gross Amounts Not Offset in the Balance Sheets
	(in thousands)	Gross Amounts Recognized			Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets			Financial Instruments		Cash Collateral Received		Net Amount
	Derivative assets	$	149,504		$	(44,135	)	$	105,369		$	—	$	—	$	105,369
	Derivative liabilities	$	56,328		$	(44,135	)	$	12,193		$	—	$	—	$	12,193

Reconciliation_of_Earnings_Per1

Reconciliation of Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Schedule of earnings per share reconciliation	'
	Years ended December 31,
	(in thousands, except per share amounts)				2013						2012					2011
		Net			Shares		Per Share Amount		Net		Shares	Per Share Amount		Net		Shares	Per Share Amount
		Income							Income					Income
	Basic EPS	$	204,554		72,318		$	2.83	$	253,562	72,119	$	3.52	$	259,624	72,056	$	3.6
	Effect of dilutive securities
	Stock options				112						196					270
	Non-vested restricted stock				20						1					6
	Performance share awards				21						—					—
	Diluted EPS	$	204,554		72,471		$	2.82	$	253,562	72,316	$	3.51	$	259,624	72,332	$	3.59
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.
	Years ended December 31, (in thousands)	2013		2012		2011
	Stock options	134,138		849,583		293,978
	Non-vested restricted stock	6,529		—		—
	Performance share awards	4,121		—		—

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of change in asset retirement obligation	'
	In 2013, 2012 and 2011, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:
	(in thousands)
	Balance as of December 31, 2010	$	97,415
	Liabilities incurred	4,627
	Liabilities settled	(1,539		)
	Accretion expense (including discontinued operations of $1,138)	6,837
	Balance as of December 31, 2011	107,340
	Liabilities incurred	3,994
	Liabilities settled	(845		)
	Accretion expense (including discontinued operations of $1,195)	7,534
	Balance as of December 31, 2012	118,023
	Liabilities incurred	2,772
	Liabilities settled	(5,525		)
	Accretion expense (including discontinued operations of $1,197)	8,192
	Reclassification associated with held for sale properties*	(14,929		)
	Balance as of December 31, 2013	$	108,533
	* Asset retirement obligation associated with North Louisiana/East Texas properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Line Items]	'
Schedule of Cash Flow, Supplemental Disclosures	'
	Supplemental information concerning Energen’s cash flow activities was as follows:
	Years ended December 31, (in thousands)	2013			2012		2011
	Interest paid, net of amount capitalized	$	65,143		$	61,379	$	33,601
	Income taxes paid	$	25,081		$	17,170	$	9,432
	Noncash investing activities:
	Accrued development, exploration costs and other capital	$	99,128		$	120,024	$	72,030
	Capitalized depreciation	$	66		$	80	$	93
	Capitalized asset retirement obligations costs	$	3,574		$	4,409	$	4,927
	Allowance for funds used during construction	$	698		$	623	$	807
	Capital lease obligations	$	—		$	5,072	$	—
	Noncash financing activities:
	Issuance of common stock for employee benefit plans	$	1,015		$	838	$	822
	Treasury stock acquired in connection with tax withholdings	$	977		$	277	$	713
Alabama Gas Corporation	'
Supplemental Cash Flow Information [Line Items]	'
Schedule of Cash Flow, Supplemental Disclosures	'
	Supplemental information concerning Alagasco’s cash flow activities was as follows:
	Years ended December 31, (in thousands)	2013			2012		2011
	Interest paid, net of amount capitalized	$	13,465		$	13,513	$	12,385
	Income taxes paid	$	23,138		$	16,796	$	5,143
	Interest expense (revenue) on affiliated company debt, net	$	(18	)	$	295	$	376
	Noncash investing activities:
	Accrued property, plant and equipment costs	$	5,505		$	3,536	$	2,229
	Capitalized depreciation	$	66		$	80	$	93
	Capitalized asset retirement obligations costs	$	802		$	415	$	300
	Allowance for funds used during construction	$	698		$	623	$	807

Acquisition_and_Dispositions_o1

Acquisition and Dispositions of Oil and Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2013
Acquisition and Dispositions of Oil and Gas Properties [Abstract]	'
Schedule of consideration paid and amounts of assets acquired and liabilities assumed	'
	The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011 (including the effects of closing adjustments).
	(in thousands)
	Consideration given
	Cash (net)	$	161,967
	Recognized amounts of identifiable assets acquired and liabilities assumed
	Proved properties	$	151,544
	Unproved leasehold properties	7,883
	Accounts receivable	3,070
	Accounts payable	(388		)
	Asset retirement obligation	(142		)
	Total identifiable net assets	$	161,967
	The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011 (including the effects of closing adjustments).
	(in thousands)
	Consideration given
	Cash (net)	$	60,017
	Recognized amounts of identifiable assets acquired and liabilities assumed
	Proved properties	$	36,068
	Unproved leasehold properties	23,686
	Accounts receivable	680
	Accounts payable	(244		)
	Asset retirement obligation	(173		)
	Total identifiable net assets	$	60,017
	The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (including the effects of closing adjustments).
	(in thousands)
	Consideration given
	Cash (net)	$	67,615
	Recognized amounts of identifiable assets acquired and liabilities assumed
	Proved properties	$	65,581
	Unproved leasehold properties	911
	Accounts receivable	1,358
	Accounts payable	(25		)
	Asset retirement obligation	(210		)
	Total identifiable net assets	$	67,615

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2013
Discontinued Operations and Disposal Groups [Abstract]	'
Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures	'
	Years ended December 31, (in thousands, except per share data)	2013			2012			2011
	Oil and gas revenues	$	60,191		$	76,350		$	110,366
	Pretax income (loss) from discontinued operations	$	10,028		$	(2,373	)	$	54,698
	Income tax expense (benefit)	2,215			(715		)	19,379
	Income (Loss) From Discontinued Operations	$	7,813		$	(1,658	)	$	35,319
	Gain on disposal of discontinued operations, net	$	5,605		$	—		$	—
	Income tax expense	2,011			—			—
	Gain on Disposal of Discontinued Operations, net	$	3,594		$	—		$	—
	Total Income (Loss) From Discontinued Operations	$	11,407		$	(1,658	)	$	35,319
	Diluted Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	0.1		$	(0.02	)	$	0.49
	Gain on Disposal of Discontinued Operations, net	0.05			—			—
	Total Income (Loss) From Discontinued Operations	$	0.15		$	(0.02	)	$	0.49
	Basic Earnings Per Average Common Share
	Income (Loss) from Discontinued Operations	$	0.11		$	(0.02	)	$	0.49
	Gain on Disposal of Discontinued Operations, net	0.05			—			—
	Total Income (Loss) From Discontinued Operations	$	0.16		$	(0.02	)	$	0.49
	The following table details held-for-sale properties by major classes of assets and liabilities:
	(in thousands)	December 31, 2013
		Black Warrior Basin			North Louisiana/East Texas			Total
	Accounts receivable	$	2,829		$	1,272		$	4,101
	Inventories	—			68			68
	Oil and gas properties	—			348,379			348,379
	Less accumulated depreciation, depletion and amortization	—			(301,609		)	(301,609		)
	Other property, net	—			165			165
	Total assets held-for-sale	2,829			48,275			51,104
	Accounts payable	(1,732		)	(11		)	(1,743		)
	Royalty payable	(550		)	(869		)	(1,419		)
	Other current liabilities	(379		)	(21		)	(400		)
	Other long-term liabilities	—			(14,983		)	(14,983		)
	Total liabilities held-for-sale	(2,661		)	(15,884		)	(18,545		)
	Total held-for-sale properties	$	168		$	32,391		$	32,559

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities (Tables) (Alabama Gas Corporation)	12 Months Ended
	Dec. 31, 2013
Alabama Gas Corporation	'
Regulatory Assets and Liabilities [Line Items]	'
Schedule of regulatory assets and liabilities	'
	The following table details regulatory assets and liabilities on the consolidated balance sheets:
	(in thousands)	December 31, 2013				December 31, 2012
		Current		Noncurrent		Current		Noncurrent
	Regulatory assets:
	Pension assets	$	325	$	58,243	$	170	$	90,708
	Accretion and depreciation for asset retirement obligation	—		18,046		—		16,536
	Risk management activities	—		—		2,593		—
	Rate recovery of asset removal costs, net	—		4,601		—		3,322
	Enhanced stability reserve	—		4,000		—		—
	Gas supply adjustment	2,406		—		42,726		—
	Other	25		—		26		—
	Total regulatory assets	$	2,756	$	84,890	$	45,515	$	110,566
	Regulatory liabilities:
	RSE adjustment	$	4,690	$	—	$	1,740	$	—
	Unbilled service margin	28,504		—		25,078		—
	Postretirement liabilities	—		26,197		—		1,237
	Refundable negative salvage	15,779		39,663		18,265		53,467
	Asset retirement obligation	—		27,528		—		24,930
	Other	33		737		33		770
	Total regulatory liabilities	$	49,006	$	94,125	$	45,116	$	80,404

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Schedule of Accumulated Other Comprehensive Income (Loss)	'
	The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.
	(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
	Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
	Other comprehensive income (loss) before reclassifications	(11,014		)	11,582			568
	Amounts reclassified from accumulated other comprehensive income (loss)	(21,004		)	8,680			(12,324		)
	Change in accumulated other comprehensive income (loss)	(32,018		)	20,262			(11,756		)
	Balance as of December 31, 2013	$	12,178		$	(32,245	)	$	(20,067	)
Reclassification out of Accumulated Other Comprehensive Income	'
	The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).
		Year ended
		31-Dec-13
	(in thousands)	Amounts Reclassified			Line Item Where Presented
	Gains and (losses) on cash flow hedges:
	Commodity contracts	$	35,684		Operating revenues
	Interest rate swap	(1,723		)	Interest expense
	Total cash flow hedges	33,961
	Income tax expense	(12,957		)
	Net of tax	21,004
	Pension and postretirement plans:
	Transition obligation	(319		)	Operations and maintenance
	Prior service cost	(257		)	Operations and maintenance
	Actuarial losses*	(12,357		)	Operations and maintenance
	Actuarial losses on settlement charges*	(421		)	Regulatory asset
	Total pension and postretirement plans	(13,354		)
	Income tax expense	4,674
	Net of tax	(8,680		)
	Total reclassifications for the period	$	12,324
	* In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million is recognized in actuarial losses above and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 is recognized in actuarial losses above and $46,000 is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

Summarized_Quarterly_Financial1

Summarized Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Line Items]	'
Schedule of quarterly operating results	'
	The Company’s business is seasonal in character. The following data summarizes quarterly operating results.
		Year ended December 31, 2013
	(in thousands, except per share amounts)	First			Second			Third			Fourth
	Operating revenues as originally reported	$	492,679		$	490,057		$	320,406		$	472,733
	Discontinued operations*	(18,663		)	(18,562		)	—			—
	Adjusted operating revenues	$	474,016		$	471,495		$	320,406		$	472,733
	Operating income (loss) as originally reported	$	105,336		$	146,304		$	(4,052	)	$	110,630
	Discontinued operations*	(3,146		)	(3,871		)	—			—
	Adjusted operating income (loss)	$	102,190		$	142,433		$	(4,052	)	$	110,630
	Income (loss) from continuing operations	$	54,694		$	80,614		$	(5,486	)	$	63,325
	Net income (loss)	$	56,692		$	83,067		$	(19,298	)	$	84,093
	Diluted earnings per average common share
	Continuing operations	$	0.76		$	1.11		$	(0.08	)	$	0.87
	Net income (loss)	$	0.78		$	1.15		$	(0.27	)	$	1.15
	Basic earnings per average common share
	Continuing operations	$	0.76		$	1.12		$	(0.08	)	$	0.87
	Net income (loss)	$	0.79		$	1.15		$	(0.27	)	$	1.16
	* As discussed in Note 13, Discontinued Operations, during the fourth quarter of 2013, the Company completed the sale of its Black Warrior Basin coalbed methane properties in Alabama. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013. Also, during the third quarter of 2013, the Company classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations.
		Year ended December 31, 2012
	(in thousands, except per share amounts)	First			Second			Third			Fourth
	Operating revenues as originally reported	$	418,444		$	470,355		$	295,324		$	433,046
	Discontinued operations	(20,255		)	(18,451		)	(18,895		)	(18,749		)
	Adjusted operating revenues	$	398,189		$	451,904		$	276,429		$	414,297
	Operating income as originally reported	$	104,170		$	220,598		$	19,458		$	115,166
	Discontinued operations	16,324			(4,751		)	(5,494		)	(3,557		)
	Adjusted operating income	$	120,494		$	215,847		$	13,964		$	111,609
	Income (loss) from continuing operations	$	67,868		$	128,305		$	(1,505	)	$	60,552
	Net income	$	57,406		$	131,287		$	2,046		$	62,823
	Diluted earnings per average common share
	Continuing operations	$	0.94		$	1.77		$	(0.02	)	$	0.84
	Net income	$	0.79		$	1.82		$	0.03		$	0.87
	Basic earnings per average common share
	Continuing operations	$	0.94		$	1.78		$	(0.02	)	$	0.84
	Net income	$	0.8		$	1.82		$	0.03		$	0.87
Alabama Gas Corporation	'
Quarterly Financial Data [Line Items]	'
Schedule of quarterly operating results	'
	Alagasco’s business is seasonal in character and influenced by weather conditions. The following data summarizes Alagasco’s quarterly operating results.
		Year ended December 31, 2013
	(in thousands)	First			Second			Third			Fourth
	Operating revenues	$	237,685		$	104,514		$	48,368		$	142,771
	Operating income (loss)	$	79,293		$	2,219		$	(22,544	)	$	34,800
	Net income (loss)	$	47,222		$	(704	)	$	(8,961	)	$	19,842
		Year ended December 31, 2012
	(in thousands)	First			Second			Third			Fourth
	Operating revenues	$	194,487		$	70,887		$	61,809		$	124,406
	Operating income (loss)	$	78,560		$	4,448		$	(12,743	)	$	22,951
	Net income (loss)	$	46,918		$	326		$	(10,039	)	$	12,197

Oil_and_Gas_Operations_Unaudit1

Oil and Gas Operations (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Schedule of capitalized costs	'
	The following table sets forth capitalized costs:
	(in thousands)	December 31, 2013			December 31, 2012
	Proved	$	7,043,779		$	6,241,148
	Unproved	168,975			197,979
	Total capitalized costs	7,212,754			6,439,127
	Accumulated depreciation, depletion and amortization	2,078,411			1,765,241
	Capitalized costs, net	$	5,134,343		$	4,673,886
Schedule of cost incurred in property acquisition, exploration and development activities	'
	The following table sets forth costs incurred in property acquisition, exploration and development activities and includes both capitalized costs and costs charged to expense during the year:
	Years ended December 31, (in thousands)	2013			2012			2011
	Property acquisition:
	Proved	$	4,661		$	79,862		$	214,993
	Unproved	26,820			58,634			91,888
	Exploration	435,636			419,284			190,854
	Development	655,353			749,256			623,775
	Total costs incurred	$	1,122,470		$	1,307,036		$	1,121,510
Schedule of results of operations from producing activities	'
	The following table sets forth results of the Company’s oil and gas operations from producing activities:
	Years ended December 31, (in thousands)	2013			2012			2011
	Gross revenues*	$	1,206,293		$	1,090,948		$	834,700
	Production (lifting costs)	351,541			278,193			226,361
	Exploration expense	27,942			19,356			12,967
	Depreciation, depletion and amortization	449,700			339,569			210,532
	Accretion expense	6,995			6,339			5,699
	Income tax expense	128,773			160,551			134,564
	Results of operations from producing activities	$	241,342		$	286,940		$	244,577
	* The years ended December 31, 2013, 2012 and 2011 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $58.8 million and a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million, respectively.
Schedule of proved developed and undeveloped oil and gas reserves	'
	The independent reservoir engineers have issued reports covering approximately 98 percent of the Company’s ending proved reserves indicating that in their judgment the estimates are reasonable in the aggregate.
	Year ended December 31, 2013	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
	Proved reserves at beginning of period	809,128		155,348		56,155		346.4
	Revisions of previous estimates	18,465		(680	)	2,211		4.6
	Purchases	282		142		56		0.2
	Extensions and discoveries	50,568		20,517		7,823		36.8
	Production	(70,506	)	(10,378	)	(3,233	)	(25.4	)
	Sales	(88,212	)	(79	)	(1	)	(14.8	)
	Proved reserves at end of period	719,725		164,870		63,011		347.8
	Proved developed reserves at end of period	623,305		113,795		42,087		259.8
	Proved undeveloped reserves at end of period	96,420		51,075		20,924		88
	Year ended December 31, 2012	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
	Proved reserves at beginning of period	957,368		129,578		53,957		343.1
	Revisions of previous estimates	(143,704	)	(8,546	)	(9,557	)	(42.1	)
	Purchases	10,656		7,950		2,569		12.4
	Extensions and discoveries	61,170		35,132		11,759		57.1
	Production	(76,362	)	(8,766	)	(2,573	)	(24.1	)
	Proved reserves at end of period	809,128		155,348		56,155		346.4
	Proved developed reserves at end of period	708,657		105,976		36,440		260.5
	Proved undeveloped reserves at end of period	100,471		49,372		19,715		85.9
	Year ended December 31, 2011	Gas MMcf		Oil MBbl		NGL MBbl		Total MMBOE
	Proved reserves at beginning of period	954,387		103,262		40,601		302.9
	Revisions of previous estimates	(12,823	)	(4,513	)	841		(5.8	)
	Purchases	19,362		12,583		5,055		20.8
	Extensions and discoveries	68,160		24,564		9,637		45.6
	Production	(71,718	)	(6,318	)	(2,177	)	(20.4	)
	Proved reserves at end of period	957,368		129,578		53,957		343.1
	Proved developed reserves at end of period	788,812		83,899		33,154		248.5
	Proved undeveloped reserves at end of period	168,556		45,679		20,803		94.6
Schedule of standardized measure of discounted future net cash flows relating to proved oil and gas reserves	'
	Years ended December 31, (in thousands)	2013			2012			2011
	Future gross revenues	$	19,509,305		$	17,735,363		$	18,196,229
	Future production costs	6,136,709			5,715,248			5,823,395
	Future development costs	1,896,602			1,892,600			1,539,072
	Future income tax expense	3,209,697			2,809,411			3,326,382
	Future net cash flows	8,266,297			7,318,104			7,507,380
	Discount at 10% per annum	4,248,456			3,618,785			3,878,217
	Standardized measure of discounted future net cash	$	4,017,841		$	3,699,319		$	3,629,163
	flows relating to proved oil and gas reserves
Schedule of principal sources of changes in standardized measure of discounted future net cash flows	'
	The following are the principal sources of changes in the standardized measure of discounted future net cash flows:
	Years ended December 31, (in thousands)	2013			2012			2011
	Balance at beginning of year	$	3,699,319		$	3,629,163		$	2,467,136
	Revisions to reserves proved in prior years:
	Net changes in prices, production costs and future development costs	566,838			(922,792		)	707,411
	Net changes due to revisions in quantity estimates	(81,762		)	(383,755		)	(80,004		)
	Development costs incurred, previously estimated	299,432			472,603			392,720
	Accretion of discount	369,932			362,916			246,714
	Changes in timing and other	(179,502		)	(317,244		)	(25,937		)
	Total revisions	974,938			(788,272		)	1,240,904
	New field discoveries and extensions, net of future production and development costs	376,326			1,025,419			755,977
	Sales of oil and gas produced, net of production costs	(1,014,593		)	(812,781		)	(763,171		)
	Purchases	4,690			189,755			232,768
	Sales	(24,876		)	—			—
	Net change in income taxes	2,037			456,035			(304,451		)
	Net change in standardized measure of discounted future net cash flows	318,522			70,156			1,162,027
	Balance at end of year	$	4,017,841		$	3,699,319		$	3,629,163

Industry_Segment_Information_T

Industry Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Schedule of segment information	'
	Years ended December 31,(in thousands)	2013			2012			2011
	Operating revenues from continuing operations
	Oil and gas operations	$	1,205,312		$	1,089,230		$	838,160
	Natural gas distribution	533,338			451,589			534,953
	Total	$	1,738,650		$	1,540,819		$	1,373,113
	Operating income (loss) from continuing operations
	Oil and gas operations	$	257,963		$	369,765		$	308,561
	Natural gas distribution	93,768			93,216			86,216
	Eliminations and corporate expenses	(530		)	(1,067		)	(1,078		)
	Total	$	351,201		$	461,914		$	393,699
	Depreciation, depletion and amortization expense from continuing operations
	Oil and gas operations	$	453,474		$	343,183		$	213,841
	Natural gas distribution	43,907			42,270			39,916
	Total	$	497,381		$	385,453		$	253,757
	Interest expense
	Oil and gas operations	$	53,981		$	49,958		$	30,907
	Natural gas distribution	15,649			16,284			14,740
	Eliminations and other	(430		)	(700		)	(825		)
	Total	$	69,200		$	65,542		$	44,822
	Income tax expense (benefit) from continuing operations
	Oil and gas operations	$	71,290		$	115,090		$	100,700
	Natural gas distribution	34,687			30,244			26,670
	Other	(695		)	(800		)	(1,048		)
	Total	$	105,282		$	144,534		$	126,322
	Capital expenditures
	Oil and gas operations	$	1,104,745		$	1,291,211		$	1,115,452
	Natural gas distribution	88,769			71,869			73,984
	Total	$	1,193,514		$	1,363,080		$	1,189,436
	Identifiable assets
	Oil and gas operations	$	5,379,135		$	4,975,170		$	4,046,242
	Natural gas distribution	1,193,413			1,177,134			1,163,959
	Eliminations and other	49,664			23,586			27,215
	Total	$	6,622,212		$	6,175,890		$	5,237,416
	Property, plant and equipment, net
	Oil and gas operations	$	5,116,958		$	4,697,683		$	3,806,787
	Natural gas distribution	885,550			842,685			813,471
	Other	1,130			1,268			518
	Total	$	6,003,638		$	5,541,636		$	4,620,776

Capitalized_Exploratory_Well_C

Capitalized Exploratory Well Costs Rollforward (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	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	$79,791	$70,437	$21,438
Additions pending determination of proved reserves	421,599	406,226	178,005
Reclassifications due to determination of proved reserves	-442,909	-396,872	-129,006
Exploratory well costs charged to expense	-881	0	0
Capitalized exploratory well costs at end of period	57,600	79,791	70,437
Exploratory wells in progress	14,794	77,693	70,437
Capitalized exploratory well costs for a period of one year or less	42,481	0	0
Capitalized exploratory well costs for a period greater than one year	1,206	2,098	0
Total capitalized exploratory well costs	$58,481	$79,791	$70,437
Wells in Process of drilling or waiting on results from completion and testing	48	'	'

Summary_of_Significant_Account3

Summary of Significant Accounting Policies (Derivative Commodity Instruments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Accounting Policies [Abstract]	'	'	'
Mark-to-market gain (loss) on derivatives	($47,832)	$58,750	($37,587)

Summary_of_Significant_Account4

Summary of Significant Accounting Policies (Utility Plant and Depreciation) (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2010

Jul. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 01, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

bbl

bbl

Refundable negative salvage

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Refundable negative salvage

Refundable negative salvage

Refundable negative salvage

Refundable negative salvage

Refundable negative salvage

Refundable negative salvage

Refundable negative salvage

APSC Approved Reduction in Depreciation Rates, June 1, 2010

Depreciation Rate, Prior to APSC Approved Reduction, June 1, 2010

Depreciation Rate, Prior to APSC Approved Reduction, June 1, 2010

Depreciation Rate, Prior to APSC Approved Reduction, June 1, 2010

Reduction in Tariff Rates

Reduction in Tariff Rates

Reduction in Tariff Rates

Reduction in Tariff Rates

Reduction in Tariff Rates

Property, Plant and Equipment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivatives transferred to not designated as hedging instruments

'

2,353,000

5,078,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Composite depreciation rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.10%

3.10%

3.20%

3.10%

Refunded negative salvage costs

'

'

'

'

'

'

'

'

'

$22,200,000

$25,600,000

$16,300,000

$14,200,000

$2,700,000

'

'

'

'

Regulatory Liability, Current

49,006,000

'

'

45,116,000

15,800,000

49,006,000

45,116,000

15,779,000

18,265,000

'

'

'

'

'

'

'

'

'

Regulatory Liability, Noncurrent

$94,125,000

'

'

$80,404,000

$39,700,000

$94,125,000

$80,404,000

$39,663,000

$53,467,000

'

'

'

'

'

'

'

'

'

Refundable negative salvage costs, term

'12 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Summary_of_Significant_Account5

Summary of Significant Accounting Policies (Taxes on revenues) (Details) (Alabama Gas Corporation, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Alabama Gas Corporation	'	'	'
Component of Other Operating Expense [Line Items]	'	'	'
Taxes on revenues	$25,870	$21,479	$25,268

Summary_of_Significant_Account6

Summary of Significant Accounting Policies (Cash Equivalents, Short-term Investments, and Stock-Based Compensation) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Excess tax benefit from share-based compensation	$3.10	$0.60	$1

Summary_of_Significant_Account7

Summary of Significant Accounting Policies (Employee Benefit Plans) (Details)	12 Months Ended
	Dec. 31, 2013
	pension_plan
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Number of non-contributory qualified pension plans	2

Regulatory_Matters_Details

Regulatory Matters (Details) (USD $)

12 Months Ended

0 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

Dec. 31, 2013

Jan. 02, 2014

Dec. 20, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 20, 2013

Dec. 31, 2013

Dec. 20, 2013

Dec. 31, 2013

Dec. 20, 2013

Subsequent Event

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Minimum

Minimum

Maximum

Maximum

Municipal gas distribution systems

Municipal gas distribution systems

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

Alabama Public Service Commission

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Force Majeure Event Costs

Force Majeure Events Costs

Self Insurance Costs

Alabama Public Service Commission

Alabama Public Service Commission

Regulatory Matters [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Approved return on equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.50%

'

10.95%

Adjusting point

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.80%

'

'

'

'

Performance based adjustments on adjusting point

'

'

500.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of equity which return is permitted

'

'

56.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase (decrease) in approved rate

'

'

1.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Allowed return on average common equity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13.15%

'

13.65%

'

Rate increases as percentage of prior year revenues

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

Revenue reductions (increase) of rate adjustments

'

$8,500,000

'

($10,300,000)

($7,800,000)

($13,000,000)

$10,600,000

$6,300,000

$6,700,000

'

'

'

'

'

'

'

'

'

'

'

Limitation on return on equity as percentage of total capitalization

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

55.00%

'

Adjustment requirement threshold for return on equity as percentage of operations and maintenance expenses to consumer price index

'

'

'

'

'

'

0.75

'

'

'

'

'

'

'

'

'

'

'

'

'

Extraordinary Operating and maintenance expenses, minimum amount, charged to enhanced stability reserve

'

'

'

'

'

'

'

'

'

'

'

'

275,000

412,500

1,000,000

'

'

'

'

'

Negative revenue variance, large commercial and industrial customer budget, minimum amount, charged to enhanced stability reserve

'

'

'

'

'

'

'

'

'

'

'

350,000

'

'

'

'

'

'

'

'

Amortization expense, enhanced stability reserve, annual amount

'

'

'

'

'

'

660,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Municipal gas distribution systems, weighted average remaining life (in years)

'13 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Municipal gas distribution systems, net acquisition adjustments

'

'

'

'

'

'

'

'

'

$3,200,000

$3,800,000

'

'

'

'

'

'

'

'

'

LongTerm_Debt_and_Notes_Payabl2

Long-Term Debt and Notes Payable (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Long-term debt	$1,403,923	$1,154,028
Less amounts due within one year	60,000	50,000
Less unamortized debt discount	459	500
Long-term debt	1,343,464	1,103,528
Medium-term Notes | Medium-term Notes, Series A and B, interest ranging from 7.125% to 7.6%, for notes due July 24, 2017 to February 15, 2028	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	154,000	154,000
Debt instrument, interest rate, minimum	7.13%	'
Debt instrument, interest rate, maximum	7.60%	'
Notes | 5% Notes	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	0	50,000
Debt instrument, interest rate	5.00%	'
Senior Notes | 4.625% Notes, due September 1, 2021	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	400,000	400,000
Debt instrument, interest rate	4.63%	'
Senior Term Loans | Senior Term Loans, (floating rate interest LIBOR plus 1.625%; 1.792% at December 31, 2013), due March 31, 2014 to December 17, 2017	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	600,000	0
Floating rate interest, plus basis points	1.79%	'
Senior Term Loans | Senior Term Loans, (floating rate interest LIBOR plus 1.625%; 1.792% at December 31, 2013), due March 31, 2014 to December 17, 2017 | LIBOR	'	'
Debt Instrument [Line Items]	'	'
Debt Instrument, basis spread on variable rate	1.63%	'
Senior Term Loans | Senior Term Loans, (floating rate interest LIBOR plus 1.375%)	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	0	300,000
Senior Term Loans | Senior Term Loans, (floating rate interest LIBOR plus 1.375%) | LIBOR	'	'
Debt Instrument [Line Items]	'	'
Debt Instrument, basis spread on variable rate	1.38%	'
Alabama Gas Corporation	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	249,923	250,028
Alabama Gas Corporation | Notes | 5.20% Notes, due January 15, 2020	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	40,000	40,000
Debt instrument, interest rate	5.20%	'
Alabama Gas Corporation | Notes | 5.70% Notes, due January 15, 2035	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	34,923	35,028
Debt instrument, interest rate	5.70%	'
Alabama Gas Corporation | Notes | 5.368% Notes, due December 1, 2015	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	80,000	80,000
Debt instrument, interest rate	5.37%	'
Alabama Gas Corporation | Notes | 5.90% Notes, due January 15, 2037	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	45,000	45,000
Debt instrument, interest rate	5.90%	'
Alabama Gas Corporation | Notes | 3.86% Notes, due December 21, 2021	'	'
Debt Instrument [Line Items]	'	'
Long-term debt	$50,000	$50,000
Debt instrument, interest rate	3.86%	'

LongTerm_Debt_and_Notes_Payabl3

Long-Term Debt and Notes Payable (Aggregate Maturities) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Maturities of Long-term Debt [Abstract]	'
2014	$60,000
2015	140,000
2016	60,000
2017	439,000
2018	0
Alabama Gas Corporation	'
Maturities of Long-term Debt [Abstract]	'
2014	0
2015	80,000
2016	0
2017	0
2018	$0

LongTerm_Debt_and_Notes_Payabl4

Long-Term Debt and Notes Payable (Textual) (Details) (USD $)	12 Months Ended								12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Nov. 30, 2011	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
				Senior Term Loans	Senior Term Loans	Senior Term Loans	Senior Term Loans	Senior Term Loans	Alabama Gas Corporation	Alabama Gas Corporation	Alabama Gas Corporation
				Swap	Swap	Senior Term Loans, (floating rate interest LIBOR plus 1.625%; 1.792% at December 31, 2013), due March 31, 2014 to December 17, 2017	Senior Term Loans, (floating rate interest LIBOR plus 1.375%)	Senior Term Loans, (floating rate interest LIBOR plus 1.375%)
				Level 2	Level 2			Swap
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Long-term debt	'	'	'	'	'	$600,000,000	$300,000,000	$200,000,000	'	'	'
Interest rate	'	'	'	'	'	'	'	2.67%	'	'	'
Interest rate swap liability, fair value	'	'	'	1,800,000	3,300,000	'	'	'	'	'	'
Cross default provision, minimum threshold amount	10,000,000	'	'	'	'	'	'	'	10,000,000	'	'
Interest expense	69,200,000	65,542,000	44,822,000	'	'	'	'	'	15,649,000	16,284,000	14,740,000
Interest expense, capitalized	$200,000	$500,000	'	'	'	'	'	'	'	'	'

LongTerm_Debt_and_Notes_Payabl5

Long-Term Debt and Notes Payable (Lines of Credit) (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Oct. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 30, 2012

Minimum

Maximum

Energen Corporation

Energen Corporation

Energen Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Syndicated Credit Facility

Minimum

Maximum

APSC Authorized Short-term Line of Credit

Syndicated Credit Facility

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum consolidated debt to capitalization ratio

65.00%

'

'

'

'

'

'

65.00%

'

'

'

'

'

Cross default provision, minimum debt default amount

$50,000,000

'

'

'

'

'

'

$50,000,000

'

'

'

'

'

Line of Credit Facility [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

Credit facilities

1,350,000,000

1,350,000,000

'

'

'

'

1,250,000,000

'

'

'

'

'

100,000,000

Debt Instrument, Term

'

'

'

'

'

'

'5 years

'

'

'

'

'

'5 years

Short-term line of credit, authorization to borrow

'

'

'

'

'

'

'

'

'

'

'

200,000,000

'

Notes payable to banks

539,000,000

643,000,000

'

'

489,000,000

566,000,000

'

50,000,000

77,000,000

'

'

'

'

Available for borrowings

811,000,000

707,000,000

'

'

'

'

'

'

'

'

'

'

'

Maximum amount outstanding at any month-end

'

'

'

'

901,000,000

643,000,000

'

75,000,000

77,000,000

'

'

'

'

Average daily amount outstanding

'

'

'

'

$804,895,000

$331,068,000

'

$35,027,000

$21,254,000

'

'

'

'

Average daily amount outstanding, weighted average interest rates

'

'

'

'

1.38%

1.82%

'

1.12%

1.44%

'

'

'

'

Amount outstanding at year-end, weighted average interest rates

'

'

'

'

1.32%

1.35%

'

1.26%

1.11%

'

'

'

'

Unused capacity, commitment fee percentage

'

'

1500.00%

2500.00%

'

'

'

'

'

1500.00%

2500.00%

'

'

Income_Taxes_Components_of_Inc

Income Taxes (Components of Income Taxes) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Taxes estimated to be payable currently:	'	'	'
Federal	$23,342	$16,295	$11,595
State	2,516	3,125	5,065
Total current	25,858	19,420	16,660
Taxes deferred:	'	'	'
Federal	85,950	119,053	125,622
State	-2,300	5,346	3,419
Total deferred	83,650	124,399	129,041
Total income tax expense	109,508	143,819	145,701
Taxes deferred:	'	'	'
Total income tax expense	105,282	144,534	126,322
Alabama Gas Corporation	'	'	'
Taxes estimated to be payable currently:	'	'	'
Federal	17,495	18,227	-1,280
State	2,192	739	-108
Total current	19,687	18,966	-1,388
Taxes deferred:	'	'	'
Federal	13,252	9,066	24,938
State	1,748	2,212	3,120
Total deferred	15,000	11,278	28,058
Total income tax expense	$34,687	$30,244	$26,670

Income_Taxes_Components_of_Inc1

Income Taxes (Components of Income Taxes, Continuing and Discontinued Operations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Income tax expense from continuing operations	$105,282	$144,534	$126,322
Income tax expense (benefit) from discontinued operations	2,215	-715	19,379
Income tax expense from gain on disposal of discontinued operations	2,011	0	0
Total income tax expense	$109,508	$143,819	$145,701

Income_Taxes_Deferred_Tax_Asse

Income Taxes (Deferred Tax Assets and Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Line Items]	'	'
Full valuation allowance	$3,000,000	'
Book basis in excess of tax basis for subsidiary	37,000,000	'
Deferred tax liability, book basis in excess of tax basis in subsidiary	14,000,000	'
Deferred tax assets:	'	'
Total deferred tax assets, Current	48,815,000	33,455,000
Total deferred tax assets, Noncurrent	19,928,000	22,760,000
Valuation allowance, Current	-299,000	-268,000
Valuation allowance, Noncurrent	-2,674,000	-2,793,000
Total deferred tax assets, net, Current	48,516,000	33,187,000
Total deferred tax assets, net, Noncurrent	17,254,000	19,967,000
Deferred tax liabilities:	'	'
Total deferred tax liabilities, Current	7,217,000	24,667,000
Total deferred tax liabilities, Noncurrent	1,030,499,000	925,568,000
Net deferred tax assets (liabilities), Current	41,299,000	8,520,000
Net deferred tax assets (liabilities), Noncurrent	-1,013,245,000	-905,601,000
Alabama Gas Corporation	'	'
Deferred tax assets:	'	'
Total deferred tax assets, net, Current	21,553,000	20,200,000
Total deferred tax assets, net, Noncurrent	1,000	2,000
Deferred tax liabilities:	'	'
Total deferred tax liabilities, Current	1,504,000	1,401,000
Total deferred tax liabilities, Noncurrent	205,632,000	189,383,000
Net deferred tax assets (liabilities), Current	20,049,000	18,799,000
Net deferred tax assets (liabilities), Noncurrent	-205,631,000	-189,381,000
Oil and Gas Operations	'	'
Income Tax Disclosure [Line Items]	'	'
Deferred Tax Assets, State Operating Loss Carryforwards and Other Tax Carryforwards, Portion About To Expire	35,000,000	'
Deferred tax assets, Current	'	'
Deferred tax assets:	'	'
Unbilled and deferred revenue	12,547,000	10,137,000
Allowance for doubtful accounts	2,066,000	2,408,000
Insurance and other accruals	4,851,000	3,821,000
Compensation accruals	15,405,000	13,116,000
Inventories	1,260,000	1,664,000
Other comprehensive income	0	0
Gas supply adjustment related accruals	698,000	969,000
Derivative instruments	10,769,000	0
State net operating losses and other carryforwards	0	0
Other	1,219,000	1,340,000
Deferred tax assets, Current | Alabama Gas Corporation	'	'
Deferred tax assets:	'	'
Unbilled and deferred revenue	12,547,000	10,137,000
Allowance for doubtful accounts	1,815,000	2,155,000
Insurance and other accruals	1,769,000	1,856,000
Compensation accruals	2,480,000	2,645,000
Inventories	1,260,000	1,664,000
Gas supply adjustment related accruals	698,000	969,000
Other	984,000	774,000
Deferred tax assets, Noncurrent	'	'
Income Tax Disclosure [Line Items]	'	'
State net operating loss carryforwards, subject to expiration	1,600,000	'
Deferred tax assets:	'	'
Unbilled and deferred revenue	0	0
Allowance for doubtful accounts	0	0
Insurance and other accruals	0	0
Compensation accruals	0	0
Inventories	0	0
Other comprehensive income	15,350,000	19,158,000
Gas supply adjustment related accruals	0	0
Derivative instruments	0	0
State net operating losses and other carryforwards	4,577,000	3,577,000
Other	1,000	25,000
Deferred tax assets, Noncurrent | Alabama Gas Corporation	'	'
Deferred tax assets:	'	'
Unbilled and deferred revenue	0	0
Allowance for doubtful accounts	0	0
Insurance and other accruals	0	0
Compensation accruals	0	0
Inventories	0	0
Gas supply adjustment related accruals	0	0
Other	1,000	2,000
Deferred tax liabilities, Current	'	'
Deferred tax liabilities:	'	'
Depreciation and basis differences	0	0
Pension and other costs	0	0
Derivative instruments	0	4,272,000
Other comprehensive income	5,540,000	18,133,000
Other	1,677,000	2,262,000
Deferred tax liabilities, Current | Alabama Gas Corporation	'	'
Deferred tax liabilities:	'	'
Depreciation and basis differences	0	0
Pension and other costs	0	0
Other	1,504,000	1,401,000
Deferred tax liabilities, Noncurrent	'	'
Deferred tax liabilities:	'	'
Depreciation and basis differences	1,008,026,000	898,625,000
Pension and other costs	15,379,000	20,143,000
Derivative instruments	2,048,000	3,162,000
Other comprehensive income	0	0
Other	5,046,000	3,638,000
Deferred tax liabilities, Noncurrent | Alabama Gas Corporation	'	'
Deferred tax liabilities:	'	'
Depreciation and basis differences	186,601,000	167,329,000
Pension and other costs	19,031,000	22,054,000
Other	$0	$0

Income_Taxes_Effective_Income_

Income Taxes (Effective Income Tax Rate Reconciliation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Line Items]	'	'	'
Statutory federal income tax rate	35.00%	35.00%	35.00%
Income tax expense at statutory federal income tax rate	$104,450	$139,914	$122,719
State income taxes, net of federal income tax benefit	3,799	4,755	8,341
Impact of state law changes	-1,966	0	-2,059
Qualified Section 199 production activities deduction	0	-61	-495
401(k) stock dividend deduction	-449	-514	-532
Other, net	-552	440	-1,652
Total income tax expense	105,282	144,534	126,322
Effective income tax rate (%)	35.28%	36.16%	36.03%
Alabama Gas Corporation	'	'	'
Income Tax Disclosure [Line Items]	'	'	'
Statutory federal income tax rate	35.00%	35.00%	35.00%
Income tax expense at statutory federal income tax rate	32,230	27,876	25,645
State income taxes, net of federal income tax benefit	2,588	2,238	2,059
Reversal of tax reserves from audit settlements, net	0	0	-1,365
Other, net	-131	130	331
Total income tax expense	$34,687	$30,244	$26,670
Effective income tax rate (%)	37.67%	37.97%	36.40%

Income_Taxes_Unrecognized_Tax_

Income Taxes (Unrecognized Tax Benefits) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized Tax Benefits, Beginning Balance	$12,555,000	$10,593,000	$24,590,000
Additions based on tax positions related to the current year	4,546,000	3,731,000	3,644,000
Additions for tax positions of prior years	366,000	269,000	2,324,000
Reductions for tax positions of prior years (lapse of statute of limitations)	'	'	-39,000
Reductions for tax positions of prior years	-46,000	-446,000	'
Lapse of statute of limitations	-1,435,000	-1,592,000	-1,482,000
Settlements	'	'	-18,444,000
Unrecognized Tax Benefits, Ending Balance	15,986,000	12,555,000	10,593,000
Gross addition (reduction)	'	'	-5,900,000
Unrecognized income tax benefit liability, additions (release)	-6,900,000	'	2,900,000
Income tax interest expense (income) (net of tax benefit) and penalties expense (income)	-15,000	-25,000	-1,400,000
Accrued interest (net of tax benefit) and penalties payments	200,000	200,000	'
IRS	'	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Settlements	'	'	-1,500,000
Alabama Gas Corporation	'	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized Tax Benefits, Beginning Balance	307,000	102,000	18,941,000
Additions based on tax positions related to the current year	'	62,000	13,000
Additions for tax positions of prior years	'	201,000	1,000
Reductions for tax positions of prior years (lapse of statute of limitations)	-31,000	-58,000	-409,000
Settlements	'	'	-18,444,000
Unrecognized Tax Benefits, Ending Balance	276,000	307,000	102,000
Income tax interest expense (income) (net of tax benefit) and penalties expense (income)	4,000	0	1,400,000
Accrued interest (net of tax benefit) and penalties payments	$8,000	$4,000	'

Employee_Benefit_Plans_Benefit

Employee Benefit Plans (Benefit Obligations) (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Pension Plans

Pension Plans

Pension Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Black Warrior Basin

Pension Plans

Pension Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Defined Benefit Plan Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated benefit obligation

'

'

'

'

$253,030,000

$269,101,000

'

'

'

'

'

'

'

'

'

'

'

Projected benefit obligation:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance at beginning of period

'

'

'

'

323,540,000

250,619,000

'

85,785,000

88,064,000

'

'

'

'

'

'

'

'

Service cost

'

'

'

'

14,173,000

10,527,000

9,173,000

1,694,000

1,853,000

1,769,000

'

'

'

'

'

'

'

Interest cost

'

'

'

'

11,239,000

10,801,000

10,960,000

3,504,000

4,248,000

4,443,000

'

'

'

'

'

'

'

Actuarial (gain) loss

'

'

'

'

-28,339,000

65,048,000

'

-21,681,000

-5,413,000

'

'

'

'

'

'

'

'

Curtailment gain

'

'

'

'

-4,223,000

0

'

-1,255,000

0

'

'

'

'

'

'

'

-1,200,000

Retiree drug subsidy program

'

'

'

'

0

0

'

261,000

360,000

'

'

'

'

'

'

'

'

Benefits paid

'

'

'

'

-23,036,000

-13,455,000

'

-4,726,000

-3,327,000

'

'

'

'

'

'

'

'

Balance at end of period

'

'

'

'

293,354,000

323,540,000

250,619,000

63,582,000

85,785,000

88,064,000

'

'

'

'

'

'

'

Plan assets:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of plan assets at beginning of period

'

'

17,399,000

26,841,000

209,424,000

195,659,000

'

87,189,000

78,121,000

'

'

'

'

'

'

'

'

Actual return on plan assets

'

'

'

'

22,977,000

24,841,000

'

14,892,000

8,778,000

'

'

'

'

'

'

'

'

Employer contributions

'

'

'

'

10,169,000

2,379,000

'

1,578,000

3,617,000

'

'

'

'

'

'

'

'

Benefits paid

'

'

'

'

-23,036,000

-13,455,000

'

-4,726,000

-3,327,000

'

'

'

'

'

'

'

'

Fair value of plan assets at end of period

'

'

17,399,000

26,841,000

219,534,000

209,424,000

195,659,000

98,933,000

87,189,000

78,121,000

'

'

'

'

'

'

'

Funded status of plan

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Funded status of plans

'

'

'

'

-73,820,000

-114,116,000

'

35,351,000

1,404,000

'

'

'

'

'

'

'

'

Amounts recognized in balance sheet

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncurrent assets

35,351,000

1,404,000

'

'

0

0

'

35,351,000

1,404,000

'

26,457,000

848,000

'

'

'

'

'

Current liabilities

'

'

'

'

-6,145,000

-3,834,000

'

0

0

'

'

'

'

'

'

'

'

Noncurrent liabilities

-67,675,000

-110,282,000

'

'

-67,675,000

-110,282,000

'

0

0

'

-20,191,000

-43,611,000

'

'

'

'

'

Net asset (liability) recognized

'

'

'

'

-73,820,000

-114,116,000

'

35,351,000

1,404,000

'

'

'

'

'

'

'

'

Amounts recognized to accumulated other comprehensive income:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Prior service costs, net of taxes

'

'

'

'

323,000

528,000

'

0

0

'

'

'

'

'

'

'

'

Net actuarial (gain) loss, net of taxes

'

'

'

'

37,479,000

52,472,000

'

-5,584,000

-715,000

'

'

'

'

'

'

'

'

Transition obligation, net of taxes

'

'

'

'

0

0

'

27,000

222,000

'

'

'

'

'

'

'

'

Total accumulated other comprehensive income (loss)

32,245,000

52,507,000

'

'

37,802,000

53,000,000

'

-5,557,000

-493,000

'

'

'

'

'

'

'

'

Regulatory Assets

'

'

'

'

'

'

'

'

'

'

'

'

58,200,000

89,500,000

'

'

'

Regulatory Liabilities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$26,200,000

$1,200,000

'

Employee_Benefit_Plans_Other_I

Employee Benefit Plans (Other Investment Assets) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Unrealized gains relating to instruments held at the reporting date	'	'	$635
Transfer out of Level 3	-14,500	0	0
Nonqualified Supplemental Retirement Plans | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	33,761	30,068	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	33,761	30,068	'
Nonqualified Supplemental Retirement Plans | Insurance contracts | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	14,805	12,999	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	14,805	12,999	'
Nonqualified Supplemental Retirement Plans | United States equities | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	5,579	4,741	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	5,579	4,741	'
Nonqualified Supplemental Retirement Plans | Global equities | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	2,338	2,109	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	2,338	2,109	'
Nonqualified Supplemental Retirement Plans | Fixed income | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	11,039	10,219	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	11,039	10,219	'
Nonqualified Supplemental Retirement Plans | Level 1 | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	7,917	6,850	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	7,917	6,850	'
Nonqualified Supplemental Retirement Plans | Level 1 | Insurance contracts | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Nonqualified Supplemental Retirement Plans | Level 1 | United States equities | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	5,579	4,741	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	5,579	4,741	'
Nonqualified Supplemental Retirement Plans | Level 1 | Global equities | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	2,338	2,109	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	2,338	2,109	'
Nonqualified Supplemental Retirement Plans | Level 1 | Fixed income | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Nonqualified Supplemental Retirement Plans | Level 2 | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	25,844	17,618	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	25,844	17,618	'
Nonqualified Supplemental Retirement Plans | Level 2 | Insurance contracts | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	14,805	7,399	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	14,805	7,399	'
Nonqualified Supplemental Retirement Plans | Level 2 | United States equities | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Nonqualified Supplemental Retirement Plans | Level 2 | Global equities | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Nonqualified Supplemental Retirement Plans | Level 2 | Fixed income | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	11,039	10,219	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	11,039	10,219	'
Nonqualified Supplemental Retirement Plans | Level 3 | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	5,600	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	5,600	'
Nonqualified Supplemental Retirement Plans | Level 3 | Insurance contracts | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	5,600	5,332
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at beginning of period	5,600	5,332	5,069
Unrealized gains relating to instruments held at the reporting date	0	268	263
Transfer out of Level 3	-5,600	0	0
Fair value of plan assets at end of period	0	5,600	5,332
Nonqualified Supplemental Retirement Plans | Level 3 | United States equities | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Nonqualified Supplemental Retirement Plans | Level 3 | Global equities | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Nonqualified Supplemental Retirement Plans | Level 3 | Fixed income | Deferred Costs, Noncurrent	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'	'	'
Fair value of plan assets at end of period	$0	$0	'

Employee_Benefit_Plans_Net_Per

Employee Benefit Plans (Net Periodic Benefit Cost) (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Mar. 31, 2013

Mar. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Long-term Disability Plan

Long-term Disability Plan

Long-term Disability Plan

Pension Plans

Pension Plans

Pension Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Pension Plans

Pension Plans

Pension Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Postretirement Benefit Plans

Components of net periodic benefit cost:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Service cost

'

'

'

'

'

'

'

$14,173,000

$10,527,000

$9,173,000

$1,694,000

$1,853,000

$1,769,000

'

'

'

'

'

'

'

'

Interest cost

'

'

'

'

'

'

'

11,239,000

10,801,000

10,960,000

3,504,000

4,248,000

4,443,000

'

'

'

'

'

'

'

'

Expected long-term return on assets

'

'

'

'

'

'

'

-14,731,000

-14,093,000

-15,471,000

-5,024,000

-4,438,000

-4,418,000

'

'

'

'

'

'

'

'

Prior service cost amortization

'

'

'

'

'

'

'

490,000

517,000

496,000

'

'

'

'

'

'

'

'

'

'

'

Actuarial loss amortization

'

'

'

'

'

'

'

13,979,000

8,603,000

6,435,000

-120,000

37,000

0

'

'

'

'

'

'

'

'

Termination benefit charge

'

'

'

-400,000

'

'

'

0

0

414,000

'

'

'

'

'

'

'

'

'

'

'

Settlement charge

800,000

'

'

'

'

'

'

1,373,000

0

0

'

'

'

'

'

'

'

'

'

'

'

Transition obligation amortization

'

'

'

'

'

'

'

'

'

'

1,296,000

1,917,000

1,917,000

'

'

'

'

'

'

'

'

Curtailment gain

'

'

'

'

'

'

'

'

'

'

-1,229,000

0

0

'

'

'

'

'

'

'

'

Net periodic expense

'

'

'

'

'

'

'

26,523,000

16,355,000

12,007,000

121,000

3,617,000

3,711,000

'

'

12,100,000

7,800,000

5,200,000

800,000

2,700,000

2,800,000

Settlement charges

'

64,000

500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Settlement charges expensed

'

18,000

100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Settlements recognized as a pension asset

'

'

'

'

'

'

'

'

'

'

'

'

'

46,000

400,000

'

'

'

'

'

'

Expense related to long-term disability plan

'

'

'

'

$600,000

$700,000

$500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Employee_Benefit_Plans_Other_C

Employee Benefit Plans (Other Comprehensive Income) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Pension Plans	'	'	'
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]	'	'	'
Net actuarial (gain) loss experienced during the year	($14,138)	$28,748	$14,312
Net actuarial loss recognized as expense	-8,934	-4,908	-3,755
Prior service cost recognized as expense	-311	-340	-298
Total recognized in other comprehensive income (loss)	-23,383	23,500	10,259
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]	'	'	'
Amortization of prior service cost	314	'	'
Amortization of net actuarial loss	5,422	'	'
Postretirement Benefit Plans	'	'	'
Defined Benefit Plan, Amounts Recognized in Other Comprehensive Income (Loss) [Abstract]	'	'	'
Net actuarial (gain) loss experienced during the year	-8,057	-1,787	2,111
Net actuarial loss recognized as expense	550	0	0
Transition obligation recognized as expense	-283	-294	-286
Total recognized in other comprehensive income (loss)	-7,790	-2,081	1,825
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]	'	'	'
Amortization of net actuarial loss	-593	'	'
Amortization of net transition obligation	$42	'	'

Employee_Benefit_Plans_Assumpt

Employee Benefit Plans (Assumptions) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]	'	'	'
Health care cost trend rate assumed for next year	6.50%	6.75%	'
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%	'
Year that rate reaches ultimate rate	'2020	'2020	'
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]	'	'	'
Effect on total service and interest cost, 1-Percentage Point Decrease	-280	'	'
Effect on total service and interest cost, 1-Percentage Point Increase	336	'	'
Effect on net postretirement benefit obligation, 1-Percentage Point Decrease	-764	'	'
Effect on net postretirement benefit obligation, 1-Percentage Point Increase	759	'	'
Pension Plans	'	'	'
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]	'	'	'
Discount rate	3.63%	4.52%	4.89%
Expected long-term return on plan assets	7.00%	7.00%	7.25%
Rate of compensation increase for pay-related plans	3.71%	3.59%	3.75%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]	'	'	'
Discount rate	4.31%	3.47%	'
Rate of compensation increase for pay-related plans	3.63%	3.71%	'
Postretirement Benefit Plans	'	'	'
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]	'	'	'
Discount rate	4.26%	4.95%	5.45%
Expected long-term return on plan assets	7.00%	7.00%	7.25%
Rate of compensation increase for pay-related plans	3.70%	3.55%	3.61%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]	'	'	'
Discount rate	4.95%	4.15%	'
Rate of compensation increase for pay-related plans	3.60%	3.70%	'

Employee_Benefit_Plans_Allocat

Employee Benefit Plans (Allocation of Plan Assets) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plans	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation, Equity securities	100.00%	'
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Postretirement Benefit Plans	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation, Equity securities	100.00%	'
Defined Benefit Plan, Actual Plan Asset Allocations	100.00%	100.00%
Equity Securities | Pension Plans	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation, Equity securities	41.00%	'
Defined Benefit Plan, Actual Plan Asset Allocations	34.00%	41.00%
Equity Securities | Postretirement Benefit Plans	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation, Equity securities	60.00%	'
Defined Benefit Plan, Actual Plan Asset Allocations	61.00%	60.00%
Debt Securities | Pension Plans	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation, Equity securities	38.00%	'
Defined Benefit Plan, Actual Plan Asset Allocations	28.00%	38.00%
Debt Securities | Postretirement Benefit Plans	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation, Equity securities	40.00%	'
Defined Benefit Plan, Actual Plan Asset Allocations	39.00%	40.00%
Other Securities | Pension Plans	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation, Equity securities	21.00%	'
Defined Benefit Plan, Actual Plan Asset Allocations	38.00%	21.00%
Other Securities | Postretirement Benefit Plans	'	'
Defined Benefit Plan, Assets, Target Allocations [Abstract]	'	'
Target allocation, Equity securities	0.00%	'
Defined Benefit Plan, Actual Plan Asset Allocations	0.00%	0.00%

Employee_Benefit_Plans_Fair_Va

Employee Benefit Plans (Fair Value of Plan Assets) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	'	'	$17,399
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at beginning of period	'	17,399	26,841
Unrealized gains (losses)	'	'	-752
Unrealized gains relating to instruments held at the reporting date	'	'	635
Settlements	'	'	-9,604
Purchases	'	'	279
Transfer out of Level 3	-14,500	0	0
Fair value of plan assets at end of period	'	'	17,399
Pension Plans	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	219,534	209,424	195,659
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	219,534	209,424	195,659
Pension Plans | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	60,240	65,689	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	60,240	65,689	'
Pension Plans | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	159,294	129,235	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	159,294	129,235	'
Pension Plans | Level 3	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	14,500	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at beginning of period	14,500	17,399	'
Unrealized gains (losses)	0	992	'
Unrealized gains relating to instruments held at the reporting date	0	242	'
Settlements	0	-4,948	'
Purchases	0	815	'
Fair value of plan assets at end of period	0	14,500	'
Pension Plans | United States equities	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	42,197	50,979	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	42,197	50,979	'
Pension Plans | United States equities | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	34,117	41,907	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	34,117	41,907	'
Pension Plans | United States equities | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	8,080	9,072	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	8,080	9,072	'
Pension Plans | United States equities | Level 3	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Pension Plans | Global equities	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	33,409	34,479	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	33,409	34,479	'
Pension Plans | Global equities | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	20,153	23,782	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	20,153	23,782	'
Pension Plans | Global equities | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	13,256	10,697	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	13,256	10,697	'
Pension Plans | Global equities | Level 3	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Pension Plans | Fixed income	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	61,121	78,806	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	61,121	78,806	'
Pension Plans | Fixed income | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Pension Plans | Fixed income | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	61,121	78,806	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	61,121	78,806	'
Pension Plans | Fixed income | Level 3	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Pension Plans | Alternative investments	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	37,292	42,159	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	37,292	42,159	'
Pension Plans | Alternative investments | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Pension Plans | Alternative investments | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	37,292	27,659	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	37,292	27,659	'
Pension Plans | Alternative investments | Level 3	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	14,500	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	14,500	'
Pension Plans | Cash and cash equivalents	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	45,515	3,001	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	45,515	3,001	'
Pension Plans | Cash and cash equivalents | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	5,970	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	5,970	0	'
Pension Plans | Cash and cash equivalents | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	39,545	3,001	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	39,545	3,001	'
Pension Plans | Cash and cash equivalents | Level 3	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Postretirement Benefit Plans	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	98,933	87,189	78,121
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	98,933	87,189	78,121
Postretirement Benefit Plans | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	60,102	52,531	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	60,102	52,531	'
Postretirement Benefit Plans | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	38,831	34,658	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	38,831	34,658	'
Postretirement Benefit Plans | United States equities	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	43,054	37,482	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	43,054	37,482	'
Postretirement Benefit Plans | United States equities | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	43,054	37,482	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	43,054	37,482	'
Postretirement Benefit Plans | United States equities | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Postretirement Benefit Plans | Global equities	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	17,048	15,049	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	17,048	15,049	'
Postretirement Benefit Plans | Global equities | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	17,048	15,049	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	17,048	15,049	'
Postretirement Benefit Plans | Global equities | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Postretirement Benefit Plans | Fixed income	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	38,831	34,658	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	38,831	34,658	'
Postretirement Benefit Plans | Fixed income | Level 1	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	0	0	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	0	0	'
Postretirement Benefit Plans | Fixed income | Level 2	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Fair value of plan assets	38,831	34,658	'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at end of period	$38,831	$34,658	'

Employee_Benefit_Plans_Cash_Fl

Employee Benefit Plans (Cash Flows) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Jan. 31, 2013
		Pension Plans	Pension Plans	Postretirement Benefit Plans	Postretirement Benefit Plans	Nonqualified Supplemental Retirement Plans	Defined Benefit Plan Discretionary Contribution [Member]
							Pension Plans
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'	'	'	'
Employer contributions	'	$10,169,000	$2,379,000	$1,578,000	$3,617,000	'	$3,000,000
Anticipated required or discretionary contributions during in next fiscal year	'	'	'	'	'	6,100,000	'
Defined Benefit Plan, Estimated Future Benefit Payments [Abstract]	'	'	'	'	'	'	'
2014	'	66,816,000	'	4,156,000	'	'	'
2015	'	16,572,000	'	4,219,000	'	'	'
2016	'	18,174,000	'	4,286,000	'	'	'
2017	'	22,167,000	'	4,362,000	'	'	'
2018	'	28,374,000	'	4,426,000	'	'	'
2019-2023	'	134,584,000	'	22,319,000	'	'	'
Disclosure of Expected Gross Prescription Drug Subsidy Receipts [Abstract]	'	'	'	'	'	'	'
Postretirement Benefits - Prescription Drug Subsidy, 2013	-212,000	'	'	'	'	'	'
Postretirement Benefits - Prescription Drug Subsidy, 2014	-218,000	'	'	'	'	'	'
Postretirement Benefits - Prescription Drug Subsidy, 2015	-224,000	'	'	'	'	'	'
Postretirement Benefits - Prescription Drug Subsidy, 2016	-227,000	'	'	'	'	'	'
Postretirement Benefits - Prescription Drug Subsidy, 2017	-231,000	'	'	'	'	'	'
Prescription Drug Subsidy Receipts, after Year Five	($1,202,000)	'	'	'	'	'	'

Common_Stock_Plans_Energen_Emp

Common Stock Plans (Energen Employee Savings Plan) (Details) (Energen Employee Savings Plan, USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Energen Employee Savings Plan	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Percentage of common stock that might be diversified into other investment options	100.00%	'	'
Total shares reserved for issuance (in shares)	1,080,108	'	'
Expense associated with contributions to employee savings plan	$8	$7.80	$6.80

Common_Stock_Plans_Stock_Incen

Common Stock Plans (Stock Incentive Plan) (Details) (Stock Incentive Plan)	Dec. 31, 2013	Apr. 27, 2011
Stock Incentive Plan	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Number of shares authorized for issuance	'	8,600,000
Number of shares remaining for issuance	2,921,392	'

Common_Stock_Plans_Performance

Common Stock Plans (Performance Share Awards) (Details) (Performance share awards, Stock Incentive Plan, USD $)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Each unit of performance share awards equivalent to market value of number of common stock (shares)	1
Shares	'
Nonvested, Beginning of Period, Shares	0
Forfeited, Shares	-8,008
Nonvested, End of Period, Shares	160,819
Weighted Average Price	'
Nonvested, Beginning of Period, Weighted Average Price (in dollars per share)	$0
Forfeited, Weighted Average Price (in dollars per share)	$60.03
Nonvested, End of Period, Weighted Average Price (in dollars per share)	$62.13
Two years vesting period	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Share-based compensation, vesting period	'2 years
Shares	'
Granted, Shares	86,221
Weighted Average Price	'
Granted, Weighted Average Price (in dollars per share)	$61.14
Three years vesting period	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Share-based compensation, vesting period	'3 years
Shares	'
Granted, Shares	82,606
Weighted Average Price	'
Granted, Weighted Average Price (in dollars per share)	$62.96

Common_Stock_Plans_Stock_Optio

Common Stock Plans (Stock Options) (Details) (Stock Incentive Plan, USD $)	0 Months Ended				12 Months Ended
	Oct. 15, 2013	Jan. 24, 2013	Jan. 25, 2012	Jan. 26, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Shares	'	'	'	'	'	'	'
Remaining reserved for issuance	'	'	'	'	2,921,392	'	'
Stock options	'	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'	'
Share-based compensation, vesting period	'	'	'	'	'3 years	'	'
Share-based compensation, expiration period	'	'	'	'	'10 years	'	'
Shares	'	'	'	'	'	'	'
Outstanding, Beginning of Period, Shares	'	'	'	'	1,648,475	1,338,241	1,276,043
Granted, Shares	3,686	134,076	371,040	293,978	137,762	371,040	293,978
Exercised, Shares	'	'	'	'	-590,119	-58,471	-227,405
Forfeited, Shares	'	'	'	'	-5,074	-2,335	-4,375
Outstanding, End of Period, Shares	'	'	'	'	1,191,044	1,648,475	1,338,241
Exercisable, Shares	'	'	'	'	713,445	987,733	677,753
Remaining reserved for issuance	'	'	'	'	2,921,392	'	'
Weighted Average Exercise Price	'	'	'	'	'	'	'
Outstanding, Beginning of Period, Weighted Average Exercise Price (in dollars per share)	'	'	'	'	$47.58	$44.77	$40.16
Granted, Weighted Average Exercise Price (in dollars per share)	'	'	'	'	$49.22	$54.11	$54.99
Exercised, Weighted Average Exercise Price (in dollars per share)	'	'	'	'	$40.92	$24.55	$32.33
Forfeited, Weighted Average Exercise Price (in dollars per share)	'	'	'	'	$51.85	$46.45	$35.35
Outstanding, End of Period, Weighted Average Exercise Price (in dollars per share)	'	'	'	'	$51.06	$47.58	$44.77
Exercisable, Weighted Average Exercise Price (in dollars per share)	'	'	'	'	$49.80	$43.75	$43.72

Common_Stock_Plans_Stock_Optio1

Common Stock Plans (Stock Options, Valuation Assumptions) (Details) (Stock options, Stock Incentive Plan, USD $)	0 Months Ended				12 Months Ended
	Oct. 15, 2013	Jan. 24, 2013	Jan. 25, 2012	Jan. 26, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock options | Stock Incentive Plan	'	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]	'	'	'	'	'	'	'
Awards granted	3,686	134,076	371,040	293,978	137,762	371,040	293,978
Fair market value of stock option at grant (in dollars per share)	$30.53	$16.66	$18.79	$19.65	'	'	'
Expected life of award	'5 years 9 months 18 days	'5 years 9 months 18 days	'5 years 9 months 18 days	'5 years 9 months 18 days	'	'	'
Risk-free interest rate	1.79%	1.01%	1.07%	2.45%	'	'	'
Annualized volatility rate	40.60%	40.30%	39.60%	37.80%	'	'	'
Dividend yield	0.70%	1.20%	1.00%	1.00%	'	'	'

Common_Stock_Plans_Stock_Optio2

Common Stock Plans (Stock Options, Textual) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Performance share awards	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based compensation expense	$4,000,000	$0	$0
Tax benefit related to stock-based compensation	1,500,000	'	'
Costs not recognized	5,500,000	'	'
Period for recognition	'1 year 5 months 26 days	'	'
Stock options | Stock Incentive Plan	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based compensation expense	3,600,000	7,000,000	5,600,000
Tax benefit related to stock-based compensation	1,400,000	2,600,000	2,100,000
Intrinsic value of stock options exercised during period	15,700,000	'	'
Cash received from exercise of stock options	17,800,000	'	'
Intrinsic value for outstanding options	23,500,000	'	'
Intrinsic value for exercisable options	14,900,000	'	'
Fair value of vested options	5,800,000	'	'
Unrecognized compensation cost	500,000	'	'
Stock Appreciation Rights | Stock Incentive Plan	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Intrinsic value of stock options exercised during period	8,500,000	'	'
Cash paid for settlement of stock appreciation rights	$5,800,000	'	'

Common_Stock_Plans_Stock_Optio3

Common Stock Plans (Stock Options, Range of Exercise Prices) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	'6 years 9 months 7 days
Number of exercisable options, Weighted Average Remaining Contractual Life (in years)	'5 years 10 months 20 days
Stock options | Stock Incentive Plan	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Range of Exercise Prices, Lower Range Limit	29.79
Number of outstanding options, Range of Exercise Prices, Upper Range Limit	80.48
Number of outstanding options, Shares	1,191,044
Stock options | Stock Incentive Plan | $46.45	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Range of Exercise Prices	46.45
Number of outstanding options, Shares	59,330
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	'3 years
Stock options | Stock Incentive Plan | $60.56	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Range of Exercise Prices	60.56
Number of outstanding options, Shares	99,965
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	'4 years
Stock options | Stock Incentive Plan | $29.79	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Range of Exercise Prices	29.79
Number of outstanding options, Shares	78,222
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	'5 years
Stock options | Stock Incentive Plan | $46.69	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Range of Exercise Prices	46.69
Number of outstanding options, Shares	203,469
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	'6 years
Stock options | Stock Incentive Plan | $54.99	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Range of Exercise Prices	54.99
Number of outstanding options, Shares	266,166
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	'7 years
Stock options | Stock Incentive Plan | $54.11	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Range of Exercise Prices	54.11
Number of outstanding options, Shares	349,754
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	'8 years
Stock options | Stock Incentive Plan | $48.36	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Range of Exercise Prices	48.36
Number of outstanding options, Shares	130,452
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	'9 years
Stock options | Stock Incentive Plan | $80.48	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Number of outstanding options, Range of Exercise Prices	80.48
Number of outstanding options, Shares	3,686
Number of outstanding options, Weighted Average Remaining Contractual Life (in years)	'9 years 9 months 29 days

Common_Stock_Plans_Restricted_

Common Stock Plans (Restricted Stock) (Details) (Non-vested restricted stock, Stock Incentive Plan, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Non-vested restricted stock | Stock Incentive Plan	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based compensation, vesting period	'3 years	'	'
Share-based compensation expense	$2,000,000	$100,000	$100,000
Tax benefit related to stock-based compensation	746,000	31,000	47,000
Unrecognized compensation cost	$1,200,000	'	'
Remaining requisite service period (in years)	'2 years 0 months 18 days	'	'
Shares	'	'	'
Nonvested, Beginning of Period, Shares	11,115	9,275	24,150
Vested, Shares	'	-9,275	-14,875
Granted, Shares	52,650	11,115	'
Forfeited, Shares	-1,247	'	'
Nonvested, End of Period, Shares	62,518	11,115	9,275
Weighted Average Price	'	'	'
Nonvested, Beginning of Period, Weighted Average Price (in dollars per share)	$45.24	$42.99	$35.49
Vested, Weighted Average Price (in dollars per share)	'	$42.97	$30.81
Granted, Weighted Average Price (in dollars per share)	$52.34	$45.24	'
Forfeited, Weighted Average Price (in dollars per share)	$48.36	'	'
Nonvested, End of Period, Weighted Average Price (in dollars per share)	$51.16	$45.24	$42.99

Common_Stock_Plans_2004_Stock_

Common Stock Plans (2004 Stock Appreciation Rights Plan) (Details) (Stock Appreciation Rights, 2004 Stock Appreciation Rights Plan, USD $)

0 Months Ended

12 Months Ended

0 Months Ended

Jan. 24, 2013

Jan. 26, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jan. 24, 2013

Jan. 26, 2011

Jan. 27, 2010

Feb. 16, 2009

Jan. 28, 2009

Feb. 04, 2008

Feb. 01, 2007

Originally reported

Originally reported

Originally reported

Originally reported

Originally reported

Originally reported

Originally reported

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Share-based compensation expense (income)

'

'

$1,500,000

($1,000,000)

$4,300,000

'

'

'

'

'

'

'

Shares

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding, Beginning of Period, Shares

'

'

653,030

777,218

656,340

'

'

'

'

'

'

'

Granted, Shares

'

'

88,000

'

189,984

'

'

'

'

'

'

'

Exercised/forfeited, Shares

'

'

-363,653

-124,188

-69,106

'

'

'

'

'

'

'

Outstanding, End of Period, Shares

'

'

377,377

653,030

777,218

'

'

'

'

'

'

'

Weighted Average Exercise Price

'

'

'

'

'

'

'

'

'

'

'

'

Outstanding, Beginning of Period, Weighted Average Exercise Price (in dollars per share)

'

'

$44.14

$42

$38.30

'

'

'

'

'

'

'

Granted, Weighted Average Exercise Price (in dollars per share)

'

'

$48.36

'

$54.99

'

'

'

'

'

'

'

Exercised/forfeited, Weighted Average Exercise Price (in dollars per share)

'

'

$39.66

$30.90

$41.21

'

'

'

'

'

'

'

Outstanding, End of Period, Weighted Average Exercise Price (in dollars per share)

'

'

$49.48

$44.14

$42

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

Awards granted

931

7,785

'

'

'

87,069

182,199

171,749

3,292

305,257

67,093,000

85,906,000

Fair market value of stock option at grant (in dollars per share)

$27.89

$24.21

'

'

'

$34.66

$27.07

$30.10

$39.87

$41.18

$18.50

$27.03

Expected life of award

'2 years 6 months

'2 years 6 months

'

'

'

'5 years 7 months 6 days

'3 years 7 months 6 days

'3 years

'2 years 6 months

'2 years 6 months

'2 years

'1 year 6 months

Risk-free interest rate

0.56%

0.56%

'

'

'

2.04%

1.06%

0.80%

0.58%

0.58%

0.39%

0.23%

Annualized volatility rate

40.60%

40.60%

'

'

'

40.60%

40.60%

40.60%

40.60%

40.60%

40.60%

40.60%

Dividend yield

0.80%

0.80%

'

'

'

0.80%

0.80%

0.80%

0.80%

0.80%

0.80%

0.80%

Common_Stock_Plans_Other_Plans

Common Stock Plans (Other Plans) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
Stock Equivalent Units | Petrotech Incentive Plan	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'	'	'	'
Outstanding, Beginning of Period, Shares	141,243	11,061	8,205	173,292
Paid, Shares	-36,792	-3,281	-1,914	'
Forfeited	-26,529	-13,476	-1,544	'
Share-based compensation expense	$6,200,000	$2,600,000	$200,000	'
Stock Equivalent Units | Petrotech Incentive Plan | Three years vesting period	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'	'	'	'
Granted	92,418	102,349	6,314	'
Share-based compensation, vesting period	'3 years	'	'	'
Stock Equivalent Units | Petrotech Incentive Plan | Two years vesting period	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'	'	'	'
Granted	'	3,768	'	'
Share-based compensation, vesting period	'2 years	'	'	'
Stock Equivalent Units | Petrotech Incentive Plan | 18-months vesting period	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'	'	'	'
Granted	'	40,822	'	'
Share-based compensation, vesting period	'18 months	'	'	'
Stock Equivalent Units | Petrotech Incentive Plan | 17-month vesting period	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'	'	'	'
Granted	2,952	'	'	'
Share-based compensation, vesting period	'17 months	'	'	'
Management | 1997 Deferred Compensation Plan	'	'	'	'
Deferred Compensation Arrangements [Abstract]	'	'	'	'
Deferred compensation, reserved for issuance	695,140	'	'	695,140
Director | Stock options | 1992 Energen Corporation Directors Stock Plan	'	'	'	'
Deferred Compensation Arrangements [Abstract]	'	'	'	'
Granted, Shares	13,500	11,120	12,420	'
Number of shares remaining for issuance	138,284	'	'	'

Common_Stock_Plans_Stock_Repur

Common Stock Plans (Stock Repurchase Program) (Details) (Common Stock, USD $)	0 Months Ended	12 Months Ended
	25-May-94	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Common Stock	'	'	'	'
Equity, Class of Treasury Stock [Line Items]	'	'	'	'
Stock repurchase program, authorized amount	$12,564,400	'	'	'
Stock repurchase program, remaining authorized repurchase amount	'	$8,992,700	'	'
Shares acquired in connection with stock compensation plans	'	14,766	5,459	12,867

Commitments_and_Contingencies_1

Commitments and Contingencies (Commitments and Agreements) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Agreement Termination	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Possible resulting exposure form discontinue use of drilling rigs	$3.90	'	'
Crude Oil	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Oil and Gas Delivery Commitments and Contracts, Remaining Contractual Volume	7.1	'	'
Alabama Gas Corporation | Natural Gas, Delivery and Storage	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Long-term contracts, amount	171	'	'
Long-term contract, period end	'September 2024	'	'
Long-term contracts expense recognized in financial statements	$50	$51	$51
Alabama Gas Corporation | Natural Gas	'	'	'
Long-term Purchase Commitment [Line Items]	'	'	'
Long-term contract, period end	'August 2020	'	'
Long-term contracts, minimum quantity commitments	134	'	'

Commitments_and_Contingencies_2

Commitments and Contingencies (Environmental Matters) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
	pit
Alabama Gas Corporation	'
Site Contingency [Line Items]	'
Chain of title, manufactured gas plant sites	9
Chain of title, manufactured gas distribution sites	5
Sites owned by Alagasco | Alabama Gas Corporation	'
Site Contingency [Line Items]	'
Chain of title, manufactured gas plant sites	4
Chain of title, manufactured gas distribution sites	1
Mitchell County, Texas	'
Site Contingency [Line Items]	'
Number of reserves pits	9
Expected environmental remediation costs	$2.10
Cost incurred, environmental remediation	1.9
Environmental remediation reserve	$0.20

Commitments_and_Contingencies_3

Commitments and Contingencies (Legal Matters and New Mexico Audits) (Details) (Unfavorable Regulatory Action, USD $)	Dec. 31, 2013
Unfavorable Regulatory Action	'
Loss Contingencies [Line Items]	'
Order for payment of additional royalties	$142,000
Preliminary estimates of order maximum liabilities for additional royalties	$23,000,000

Commitments_and_Contingencies_4

Commitments and Contingencies (Lease Obligations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Leased Assets [Line Items]	'	'	'
Total lease payments	$25,000,000	$20,900,000	$19,100,000
Operating Leases, Future Minimum Payments Due [Abstract]	'	'	'
2014	5,270,000	'	'
2015	4,940,000	'	'
2016	4,391,000	'	'
2017	3,980,000	'	'
2018	2,409,000	'	'
2019 and thereafter	10,637,000	'	'
Alabama Gas Corporation	'	'	'
Operating Leased Assets [Line Items]	'	'	'
Total lease payments	2,400,000	2,100,000	2,300,000
Lease expense paid by parent company	700,000	1,000,000	1,000,000
Operating Leases, Future Minimum Payments Due [Abstract]	'	'	'
2014	4,291,000	'	'
2015	4,062,000	'	'
2016	3,994,000	'	'
2017	3,979,000	'	'
2018	2,409,000	'	'
2019 and thereafter	10,637,000	'	'
Alabama Gas Corporation | Company's headquarters	'	'	'
Operating Leased Assets [Line Items]	'	'	'
Leasing term	'25 years	'	'
Payments associated with leasing of Company's headquarters	$16,200,000	'	'

Financial_Instruments_and_Risk2

Financial Instruments and Risk Management (Financial Instruments and Finance Receivables) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	counterparty
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Number of Active Counterparties with Whom Company Holds Net Gain Positions	7	'
Number of Active Counterparties with Whom Company Holds Net Loss Positions	6	'
Number of Large Counterparties with Whom Company Holds Net Loss Positions	2	'
Financing Receivable, Allowance for Credit Losses [Roll Forward]	'	'
Allowance for credit losses, beginning balance	$470,000	$421,000
Provision	-47,000	49,000
Allowance for credit losses, ending balance	423,000	470,000
Fair Value	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt, Fair Value	1,420,700,000	1,255,800,000
Carrying Value	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt, Fair Value	1,403,900,000	1,154,000,000
Alabama Gas Corporation	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Recorded Unconditional Purchase Obligation	500,000	'
Recorded Unconditional Purchase Obligation, Market Value	600,000	'
Financing Receivable	10,800,000	10,700,000
Financing Receivable, Recorded Investment, Average Balance 0 to 60 Days Past Due	3,000	'
Average Finance Receivable Term	'84 months	'
Financing Receivable, Recorded Investment, Equal to Greater than 90 Days Past Due	400,000	500,000
Alabama Gas Corporation | Fair Value	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt, Fair Value	258,800,000	284,700,000
Alabama Gas Corporation | Carrying Value	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt, Fair Value	$249,900,000	$250,000,000

Financial_Instruments_and_Risk3

Financial Instruments and Risk Management (Risk Management) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]	'	'
Derivative, Net Gain Position	$22,902,000	$105,369,000
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	44,215,000	149,504,000
Derivative Liability, Fair Value, Gross Liability	-51,615,000	-56,328,000
Derivative, Fair Value, Net	'	93,176,000
Deferred Tax Assets (Liabilities), Net [Abstract]	'	'
Deferred tax assets (liabilities), net	-8,200,000	-28,400,000
Designated as Hedging Instrument	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	'	125,468,000
Derivative Liability, Fair Value, Net	'	-52,862,000
Derivative, Fair Value, Net	'	72,606,000
Designated as Hedging Instrument | Accounts receivable	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	'	87,514,000
Derivative Liability, Fair Value, Gross Asset	'	-37,326,000
Designated as Hedging Instrument | Other Assets	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	'	37,954,000
Derivative Liability, Fair Value, Gross Asset	'	-6,810,000
Designated as Hedging Instrument | Other Liabilities	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	'	-8,726,000
Not Designated as Hedging Instrument	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	44,216,000	24,037,000
Derivative Liability, Fair Value, Gross Liability	-51,616,000	-3,467,000
Derivative, Fair Value, Net	-7,400,000	20,570,000
Not Designated as Hedging Instrument | Accounts receivable	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	36,224,000	14,604,000
Derivative Liability, Fair Value, Gross Liability	-18,761,000	'
Not Designated as Hedging Instrument | Long-term asset derivative instruments	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	-2,553,000	'
Not Designated as Hedging Instrument | Other Assets	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	7,992,000	9,433,000
Not Designated as Hedging Instrument | Accounts Payable	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	-30,302,000	-2,593,000
Not Designated as Hedging Instrument | Other Liabilities	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	'	-874,000
Oil and Gas Operations	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative, Fair Value, Net	'	95,769,000
Oil and Gas Operations | Designated as Hedging Instrument	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	'	125,468,000
Derivative Liability, Fair Value, Net	'	-52,862,000
Derivative, Fair Value, Net	'	72,606,000
Oil and Gas Operations | Designated as Hedging Instrument | Accounts receivable	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	'	87,514,000
Derivative Liability, Fair Value, Gross Asset	'	-37,326,000	[1]
Oil and Gas Operations | Designated as Hedging Instrument | Other Assets	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	'	37,954,000
Derivative Liability, Fair Value, Gross Asset	'	-6,810,000	[1]
Oil and Gas Operations | Designated as Hedging Instrument | Other Liabilities	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	'	-8,726,000
Oil and Gas Operations | Not Designated as Hedging Instrument	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	44,216,000	24,037,000
Derivative Liability, Fair Value, Gross Liability	-51,616,000	-874,000
Derivative, Fair Value, Net	-7,400,000	23,163,000
Oil and Gas Operations | Not Designated as Hedging Instrument | Accounts receivable	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	36,224,000	14,604,000	[1]
Derivative Liability, Fair Value, Gross Liability	-18,761,000	'
Oil and Gas Operations | Not Designated as Hedging Instrument | Long-term asset derivative instruments	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	-2,553,000	'
Oil and Gas Operations | Not Designated as Hedging Instrument | Other Assets	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	7,992,000	9,433,000	[1]
Oil and Gas Operations | Not Designated as Hedging Instrument | Accounts Payable	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	-30,302,000	0
Oil and Gas Operations | Not Designated as Hedging Instrument | Other Liabilities	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	'	-874,000
Natural Gas Distribution	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative, Fair Value, Net	'	-2,593,000
Natural Gas Distribution | Designated as Hedging Instrument	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	'	0
Derivative Liability, Fair Value, Net	'	0
Derivative, Fair Value, Net	'	0
Natural Gas Distribution | Designated as Hedging Instrument | Accounts receivable	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	'	0
Derivative Liability, Fair Value, Gross Asset	'	0
Natural Gas Distribution | Designated as Hedging Instrument | Other Assets	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	'	0
Derivative Liability, Fair Value, Gross Asset	'	0
Natural Gas Distribution | Designated as Hedging Instrument | Other Liabilities	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	'	0
Natural Gas Distribution | Not Designated as Hedging Instrument	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	0	0
Derivative Liability, Fair Value, Gross Liability	0	-2,593,000
Derivative, Fair Value, Net	0	-2,593,000
Natural Gas Distribution | Not Designated as Hedging Instrument | Accounts receivable	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	0	0
Derivative Liability, Fair Value, Gross Liability	0	'
Natural Gas Distribution | Not Designated as Hedging Instrument | Long-term asset derivative instruments	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	0	'
Natural Gas Distribution | Not Designated as Hedging Instrument | Other Assets	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Gross Amounts Recognized	0	0
Natural Gas Distribution | Not Designated as Hedging Instrument | Accounts Payable	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	0	-2,593,000
Natural Gas Distribution | Not Designated as Hedging Instrument | Other Liabilities	'	'
Derivative, Fair Value, Net [Abstract]	'	'
Derivative Liability, Fair Value, Gross Liability	'	0
Cash Flow Hedges | Macquarie Bank Limited	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative, Net Gain Position	8,600,000	'
Cash Flow Hedges | J Aron & Company	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative, Net Gain Position	$5,300,000	'
[1]	Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

Financial_Instruments_and_Risk4

Financial Instruments and Risk Management (Derivative Instruments by Income Statement Location) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) recognized in OCI, tax	($6,660,000)	$40,720,000	$41,399,000
Deferred net gains (losses) on derivative instruments recorded in AOCI, net of tax, expected to be reclasses during next 12 months	13,400,000	'	'
Designated as Hedging Instrument	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Net gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($6,660), $40,720 and $41,399	-10,866,000	66,438,000	67,547,000
Designated as Hedging Instrument | Operating revenues	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain reclassified from accumulated OCI into income (effective portion)	34,293,000	52,694,000	26,326,000
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	835,000	-5,340,000	-2,767,000
Not Designated as Hedging Instrument | Operating revenues	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) recognized in income on derivative	($73,980,000)	$61,841,000	($37,587,000)

Financial_Instruments_and_Risk5

Financial Instruments and Risk Management (Derivative Instruments, Notional Amounts) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net [Abstract]	'
Discontinued hedge accounting and reclass of gains (losses) after-tax, due to probability that certain forecasted volumes would not occur	$4.50
Fair Value Hedging | Expires during 2014 | Natural Gas	'
Derivative [Line Items]	'
Total hedged Volumes	100,000,000
Fair Value Hedging | Expires during 2014 | Crude Oil	'
Derivative [Line Items]	'
Total hedged Volumes	9,800,000
Fair Value Hedging | Expires during 2014 | Natural Gas Liquids	'
Derivative [Line Items]	'
Total hedged Volumes	0
Fair Value Hedging | Expires during 2015 | Natural Gas	'
Derivative [Line Items]	'
Total hedged Volumes	0
Fair Value Hedging | Expires during 2015 | Crude Oil	'
Derivative [Line Items]	'
Total hedged Volumes	5,800,000
Cash Flow Hedges | 2014 | Natural Gas | NYMEX Swaps	'
Derivative [Line Items]	'
Total hedged Volumes	10.6
Average Contract Price, Per Mcf	4.55
Cash Flow Hedges | 2014 | Natural Gas | San Juan Basin	'
Derivative [Line Items]	'
Total hedged Volumes	31.4
Average Contract Price, Per Mcf	4.6
Cash Flow Hedges | 2014 | Natural Gas | Permian Basin	'
Derivative [Line Items]	'
Total hedged Volumes	9.7
Average Contract Price, Per Mcf	3.81
Cash Flow Hedges | 2014 | Crude Oil | NYMEX Swaps	'
Derivative [Line Items]	'
Total hedged Volumes	9,796
Average Contract Price, Per Bbl	92.64
Cash Flow Hedges | 2015 | Natural Gas | San Juan Basin	'
Derivative [Line Items]	'
Total hedged Volumes	6
Average Contract Price, Per Mcf	4.07
Cash Flow Hedges | 2015 | Crude Oil | NYMEX Swaps	'
Derivative [Line Items]	'
Total hedged Volumes	5,760
Average Contract Price, Per Bbl	88.85

Financial_Instruments_and_Risk6

Financial Instruments and Risk Management (Derivative Instruments, Fair Value) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
Derivative [Line Items]	'		'
Noncurrent assets	$5,439,000		$40,577,000
Noncurrent liabilities	-398,000		-11,305,000
Expected change in fair value of open Level 3 derivative contracts	19,000,000		'
Resulting impact upon the results of operations associated with open Level 3 mark-to-market derivative contracts	19,000,000		'
Fair Value, Measurements, Recurring	'		'
Derivative [Line Items]	'		'
Current assets	17,463,000		64,792,000
Noncurrent assets	5,439,000		40,577,000
Current liabilities	-30,302,000		-2,593,000
Noncurrent liabilities	'		-9,600,000
Net derivative asset	-7,400,000		93,176,000
Level 2 | Fair Value, Measurements, Recurring	'		'
Derivative [Line Items]	'		'
Current assets	-1,658,000	[1]	-3,629,000	[1]
Noncurrent assets	4,383,000	[1]	18,899,000	[1]
Current liabilities	-28,414,000	[1]	-2,593,000	[1]
Noncurrent liabilities	'		-8,520,000	[1]
Net derivative asset	-25,689,000	[1]	4,157,000	[1]
Level 3 | Fair Value, Measurements, Recurring	'		'
Derivative [Line Items]	'		'
Current assets	19,121,000	[1]	68,421,000	[1]
Noncurrent assets	1,056,000	[1]	21,678,000	[1]
Current liabilities	-1,888,000	[1]	0	[1]
Noncurrent liabilities	'		-1,080,000	[1]
Net derivative asset	18,289,000	[1]	89,019,000	[1]
Alabama Gas Corporation | Level 2 | Fair Value, Measurements, Recurring	'		'
Derivative [Line Items]	'		'
Current liabilities	$0		($2,600,000)
[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.

Financial_Instruments_and_Risk7

Financial Instruments and Risk Management (Derivative Instruments Change in Fair Value of Level 3) (Details) (Derivative Commodity Instruments, USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Derivative Commodity Instruments	'		'		'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'		'		'
Balance at beginning of period	$89,019,000		$65,801,000		$42,755,000
Realized gains	55,210,000		63,720,000		52,716,000
Unrealized gains (losses) relating to instruments held at the reporting date	-71,367,000	[1]	22,160,000	[1]	23,980,000	[1]
Settlements during period	-54,573,000		-62,662,000		-53,650,000
Balance at end of period	18,289,000		89,019,000		65,801,000
Unrealized gain (loss) on derivatives and commodity contracts	($7,600,000)		$19,900,000		($5,200,000)
[1]	Includes $7.6 million in mark-to-market losses, $19.9 million in mark-to-market gains and $5.2 million in mark-to-market losses for the years ended December 31, 2013, 2012 and 2011, respectively.

Financial_Instruments_and_Risk8

Financial Instruments and Risk Management (Concentration of Credit Risk) (Details)	12 Months Ended
	Dec. 31, 2013
Natural Gas Distribution	'
Concentration Risk [Line Items]	'
Number of customers	422,000
Largest Oil & Gas Purchasers, One | Accounts receivable	'
Concentration Risk [Line Items]	'
Concentration of credit risk	35.00%
Largest Oil & Gas Purchasers, One | Total operating revenues	'
Concentration Risk [Line Items]	'
Concentration of credit risk	25.00%
Largest Oil & Gas Purchasers, Two | Accounts receivable	'
Concentration Risk [Line Items]	'
Concentration of credit risk	12.00%
Largest Oil & Gas Purchasers, Two | Total operating revenues	'
Concentration Risk [Line Items]	'
Concentration of credit risk	10.00%
Largest Oil & Gas Purchasers, Three | Accounts receivable	'
Concentration Risk [Line Items]	'
Concentration of credit risk	9.00%

Financial_Instruments_and_Risk9

Financial Instruments and Risk Management (Level 3 Fair Value Measurements of Derivative Commodity Instruments) (Details) (Level 3, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Natural Gas | San Juan Basin | 2014	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Net derivative asset (liability), at fair value (in USD)	$18,159
Natural Gas | San Juan Basin | 2015	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Net derivative asset (liability), at fair value (in USD)	1,056
Natural Gas | Permian Basin | 2015	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Net derivative asset (liability), at fair value (in USD)	-1,948
Natural Gas Liquids | Liquids Swaps | 2014	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Net derivative asset (liability), at fair value (in USD)	$1,022
Discounted Cash Flow Valuation Technique | Minimum | Natural Gas | San Juan Basin | 2014	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.17	[1]
Discounted Cash Flow Valuation Technique | Minimum | Natural Gas | San Juan Basin | 2015	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.26	[1]
Discounted Cash Flow Valuation Technique | Minimum | Natural Gas | Permian Basin | 2014	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.18	[1]
Discounted Cash Flow Valuation Technique | Minimum | Natural Gas Liquids | Liquids Swaps | 2014	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Fair value inputs, derivative, nonmonetary notional amount (USD per gal)	0.8	[1]
Discounted Cash Flow Valuation Technique | Maximum | Natural Gas | San Juan Basin | 2014	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.2	[1]
Discounted Cash Flow Valuation Technique | Maximum | Natural Gas | San Juan Basin | 2015	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.26	[1]
Discounted Cash Flow Valuation Technique | Maximum | Natural Gas | Permian Basin | 2014	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Fair value inputs, derivative, nonmonetary notional amount (USD per Mcf)	0.2	[1]
Discounted Cash Flow Valuation Technique | Maximum | Natural Gas Liquids | Liquids Swaps | 2014	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'
Fair value inputs, derivative, nonmonetary notional amount (USD per gal)	0.81	[1]
[1]	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.

Recovered_Sheet1

Financial Instruments and Risk Management (Offsetting Assets and Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Gross Amounts Recognized	$44,215	$149,504
Gross Amounts Offset in the Balance Sheets	-21,313	-44,135
Net Amount Presented in the Balance Sheets	22,902	105,369
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Amount	22,902	105,369
Gross Amounts Recognized	51,615	56,328
Gross Amounts Offset in the Balance Sheets	-21,313	-44,135
Net Amount Presented in the Balance Sheets	30,302	12,193
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Amount	$30,302	$12,193

Reconciliation_of_Earnings_Per2

Reconciliation of Earnings Per Share (Reconciliation) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share Reconciliation	'	'	'	'	'	'	'	'	'	'	'
Net Income, Basic EPS	$84,093	($19,298)	$83,067	$56,692	$62,823	$2,046	$131,287	$57,406	$204,554	$253,562	$259,624
Basic Shares Outstanding (in shares)	'	'	'	'	'	'	'	'	72,317,865	72,119,021	72,055,661
Earnings Per Share, Basic (dollars per share)	$1.16	($0.27)	$1.15	$0.79	$0.87	$0.03	$1.82	$0.80	$2.83	$3.52	$3.60
Effect of dilutive securities	'	'	'	'	'	'	'	'	'	'	'
Net Income, Diluted EPS	$84,093	($19,298)	$83,067	$56,692	$62,823	$2,046	$131,287	$57,406	$204,554	$253,562	$259,624
Diluted Shares Outstanding (in shares)	'	'	'	'	'	'	'	'	72,470,622	72,316,214	72,332,369
Earnings Per Share, Diluted (dollars per share)	$1.15	($0.27)	$1.15	$0.78	$0.87	$0.03	$1.82	$0.79	$2.82	$3.51	$3.59
Stock options	'	'	'	'	'	'	'	'	'	'	'
Effect of dilutive securities	'	'	'	'	'	'	'	'	'	'	'
Incremental Common Shares Attributable to Share-based Payment Arrangements	'	'	'	'	'	'	'	'	112,000	196,000	270,000
Non-vested restricted stock	'	'	'	'	'	'	'	'	'	'	'
Effect of dilutive securities	'	'	'	'	'	'	'	'	'	'	'
Incremental Common Shares Attributable to Share-based Payment Arrangements	'	'	'	'	'	'	'	'	20,000	1,000	6,000
Performance share awards	'	'	'	'	'	'	'	'	'	'	'
Effect of dilutive securities	'	'	'	'	'	'	'	'	'	'	'
Incremental Common Shares Attributable to Share-based Payment Arrangements	'	'	'	'	'	'	'	'	21,000	0	0

Reconciliation_of_Earnings_Per3

Reconciliation of Earnings Per Share (Antidilutive Securities) (Details)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Stock options	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'
Antidilutive securities excluded from computation of diluted EPS (in options or shares)	134,138	849,583	293,978
Non-vested restricted stock	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'
Antidilutive securities excluded from computation of diluted EPS (in options or shares)	6,529	0	0
Performance share awards	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'
Antidilutive securities excluded from computation of diluted EPS (in options or shares)	4,121	0	0

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'	'
Balance of ARO, beginning	$118,023		$107,340	$97,415
Liabilities incurred	2,772		3,994	4,627
Liabilities settled	-5,525		-845	-1,539
Accretion expense	8,192		7,534	6,837
Reclassification associated with held for sale properties	-14,929	[1]	'	'
Balance of ARO, end	108,533		118,023	107,340
Regulatory Assets and Liabilities Disclosure [Abstract]	'		'	'
Regulatory Assets, Noncurrent	84,890		110,566	'
Accretion expense from discontinued operations	1,197		1,195	1,138
Alabama Gas Corporation	'		'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'	'
Balance of ARO, end	27,500		24,900	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'		'	'
Regulatory Assets, Noncurrent	84,890		110,566	'
Alabama Gas Corporation | Asset removal costs	'		'	'
Regulatory Assets and Liabilities Disclosure [Abstract]	'		'	'
Regulatory Assets, Noncurrent	$4,601		$3,322	'
[1]	Asset retirement obligation associated with North Louisiana/East Texas properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flow Information [Line Items]	'	'	'
Interest paid, net of amount capitalized	$65,143	$61,379	$33,601
Income taxes paid	25,081	17,170	9,432
Noncash investing activities:	'	'	'
Accrued development, exploration costs and other capital	99,128	120,024	72,030
Capitalized depreciation	66	80	93
Capitalized asset retirement obligations costs	3,574	4,409	4,927
Allowance for funds used during construction	698	623	807
Capital lease obligations	0	5,072	0
Issuance of common stock for employee benefit plans	1,015	838	822
Treasury stock acquired in connection with tax withholdings	977	277	713
Alabama Gas Corporation	'	'	'
Supplemental Cash Flow Information [Line Items]	'	'	'
Interest paid, net of amount capitalized	13,465	13,513	12,385
Income taxes paid	23,138	16,796	5,143
Interest expense (revenue) on affiliated company debt, net	-18	295	376
Noncash investing activities:	'	'	'
Accrued development, exploration costs and other capital	5,505	3,536	2,229
Capitalized depreciation	66	80	93
Capitalized asset retirement obligations costs	802	415	300
Allowance for funds used during construction	$698	$623	$807

Acquisition_and_Dispositions_o2

Acquisition and Dispositions of Oil and Gas Properties (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Feb. 21, 2012

1-May-12

Feb. 14, 2012

Dec. 31, 2012

Feb. 14, 2012

Feb. 14, 2012

Feb. 14, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 27, 2011

Dec. 27, 2011

Dec. 27, 2011

Dec. 27, 2011

Nov. 16, 2011

Nov. 16, 2011

Nov. 16, 2011

Nov. 16, 2011

Jul. 31, 2011

Apr. 30, 2011

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Aug. 31, 2013

Sep. 30, 2013

MMBoe

MMBoe

MMBoe

MMBoe

MMBoe

MMBoe

Feb 21, 2012, Reeves County

Feb 21, 2012, Reeves County

Feb 14, 2012, Permian Basin

Feb 14, 2012, Permian Basin

Feb 14, 2012, Permian Basin

Feb 14, 2012, Permian Basin

Feb 14, 2012, Permian Basin

December 2012, Permian Basin

Unproved Leasehold Properties

Dec 27, 2011, Permian Basin

Dec 27, 2011, Permian Basin

Dec 27, 2011, Permian Basin

Dec 27, 2011, Permian Basin

Nov 16, 2011, Permian Basin

Nov 16, 2011, Permian Basin

Nov 16, 2011, Permian Basin

Nov 16, 2011, Permian Basin

July 2011, Permian Basin

April 2011, Permian Basin

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Alabama Gas Corporation

Birmingham Metro Operations Center

Birmingham Metro Operations Center

acre

Contingent Sales Agreement

MMBoe

Oil Reserves

Natural Gas Liquids Reserves

Natural Gas Reserves

MMBoe

Oil Reserves

Natural Gas Liquids Reserves

Natural Gas Reserves

MMBoe

Oil Reserves

Natural Gas Liquids Reserves

Natural Gas Reserves

acre

Alabama Gas Corporation

Alabama Gas Corporation

well

acre

Significant Acquisitions and Disposals [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain of disposition of Metro Operations Center

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$10,900,000

'

Sales price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13,800,000

Lease back period after sale

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'20 months

'

Acquisitions, net of cash acquired

'

'

'

'

'

'

'

'

-31,331,000

-139,563,000

-310,193,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Significant Acquisitions and Disposals, Percentage of Undivided Interest, Sale

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquisition Oil and Gas Properties, Number of Wells

'

'

'

'

'

'

'

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash received from sale of oil properties

'

'

'

'

'

'

'

'

'

'

'

'

18,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net acres

'

'

'

'

'

'

'

'

'

'

'

'

4,829

51,720

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Consideration - Purchase Price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

67,615,000

'

'

'

'

18,700,000

18,000,000

60,017,000

'

'

'

161,967,000

'

'

'

20,000,000

37,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Proved reserves acquired

347.8

'

'

'

346.4

'

'

'

347.8

346.4

343.1

302.9

'

'

8.2

'

'

'

'

'

'

3.4

'

'

'

13.6

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of undeveloped portion of proved reserves

'

'

'

'

'

'

'

'

45.00%

59.00%

69.00%

'

'

'

81.00%

'

'

'

'

'

'

77.00%

'

'

'

76.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acquired proved reserves by type of reserve, percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

64.00%

22.00%

14.00%

'

'

'

61.00%

24.00%

15.00%

'

59.00%

25.00%

16.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Oil and Gas Property Acquisition, Pro Forma Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating revenue

472,733,000

320,406,000

471,495,000

474,016,000

414,297,000

276,429,000

451,904,000

398,189,000

1,738,650,000

1,540,819,000

1,373,113,000

'

'

'

'

11,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

142,771,000

48,368,000

104,514,000

237,685,000

124,406,000

61,809,000

70,887,000

194,487,000

'

'

'

'

'

Operating income (loss) from continuing operations

110,630,000

-4,052,000

142,433,000

102,190,000

111,609,000

13,964,000

215,847,000

120,494,000

351,201,000

461,914,000

393,699,000

'

'

'

'

3,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

34,800,000

-22,544,000

2,219,000

79,293,000

22,951,000

-12,743,000

4,448,000

78,560,000

59,081,000

62,972,000

59,546,000

'

'

Recognized amounts of identifiable assets acquired and liabilities assumed

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proved properties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

65,581,000

'

'

'

'

'

'

36,068,000

'

'

'

151,544,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unproved leasehold properties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

911,000

'

'

'

'

'

'

23,686,000

'

'

'

7,883,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accounts receivable

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,358,000

'

'

'

'

'

'

680,000

'

'

'

3,070,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accounts payable

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-25,000

'

'

'

'

'

'

-244,000

'

'

'

-388,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset retirement obligation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-210,000

'

'

'

'

'

'

-173,000

'

'

'

-142,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total identifiable net assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$67,615,000

'

'

'

'

'

'

$60,017,000

'

'

'

$161,967,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Discontinued_Operations_Narrat

Discontinued Operations Narrative (Details) (USD $)

3 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Oct. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2013

Jan. 31, 2014

Dec. 31, 2012

Dec. 31, 2012

Natural Gas Reserves

Natural Gas Reserves

Natural Gas Reserves

Oil Reserves

Oil Reserves

Oil Reserves

Black Warrior Basin

Black Warrior Basin

Black Warrior Basin

North Louisiana/East Texas

North Louisiana/East Texas

North Louisiana/East Texas

North Louisiana/East Texas

North Louisiana/East Texas

MMcf

MMcf

MMcf

MBbls

MBbls

MBbls

Natural Gas Reserves

Alabama

Alabama

Subsequent Event

Natural Gas Reserves

Oil Reserves

MMcf

MMcf

bbl

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash received from sale of oil properties

'

'

'

'

'

'

'

'

'

'

'

$160,000,000

'

'

'

'

'

'

Gain on sale of oil and gas property

'

'

'

'

'

'

'

'

'

'

'

'

35,000,000

'

'

'

'

'

Proved developed reserves at end of period (volume)

'

'

'

'

623,305

708,657

788,812

113,795

105,976

83,899

0

'

'

'

'

'

0

0

Sales price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

31,500,000

'

'

Impairments of oil and gas property

'

'

'

'

'

'

'

'

'

'

'

'

'

5,200,000

24,600,000

'

'

'

Asset impairment

$21,500,000

$29,794,000

$21,545,000

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Discontinued_Operations_Income

Discontinued Operations Income Statement and Balance Sheet (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, except Per Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Assets of Disposal Group, Including Discontinued Operation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Accounts receivable

$4,101

'

'

'

'

'

'

'

$4,101

'

'

Inventories

68

'

'

'

'

'

'

'

68

'

'

Oil and gas properties

348,379

'

'

'

'

'

'

'

348,379

'

'

Less accumulated depreciation, depletion and amortization

-301,609

'

'

'

'

'

'

'

-301,609

'

'

Other property, net

165

'

'

'

'

'

'

'

165

'

'

Total assets held-for-sale

51,104

'

'

'

'

'

'

'

51,104

'

'

Liabilities of Disposal Group, Including Discontinued Operation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Accounts payable

-1,743

'

'

'

'

'

'

'

-1,743

'

'

Royalty payable

-1,419

'

'

'

'

'

'

'

-1,419

'

'

Other current liabilities

-400

'

'

'

'

'

'

'

-400

'

'

Other long-term liabilities

-14,983

'

'

'

'

'

'

'

-14,983

'

'

Total liabilities held-for-sale

-18,545

'

'

'

'

'

'

'

-18,545

'

'

Total held-for-sale properties

32,559

'

'

'

'

'

'

'

32,559

'

'

Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Oil and gas revenues

0

[1]

0

[1]

-18,562

[1]

-18,663

[1]

-18,749

-18,895

-18,451

-20,255

60,191

76,350

110,366

Pretax income (loss) from discontinued operations

'

'

'

'

'

'

'

'

10,028

-2,373

54,698

Income tax expense (benefit)

'

'

'

'

'

'

'

'

2,215

-715

19,379

Income (Loss) From Discontinued Operations

'

'

'

'

'

'

'

'

7,813

-1,658

35,319

Gain on disposal of discontinued operations, net

'

'

'

'

'

'

'

'

5,605

0

0

Income tax expense

'

'

'

'

'

'

'

'

2,011

0

0

Gain on Disposal of Discontinued Operations, net

'

'

'

'

'

'

'

'

3,594

0

0

Total Income (Loss) From Discontinued Operations

'

'

'

'

'

'

'

'

11,407

-1,658

35,319

Income (Loss) from Discontinued Operations (in dollars per share)

'

'

'

'

'

'

'

'

$0.10

($0.02)

$0.49

Gain on Disposal of Discontinued Operations (in dollars per share)

'

'

'

'

'

'

'

'

$0.05

$0

$0

Total Income (Loss) From Discontinued Operations (in dollars per share)

'

'

'

'

'

'

'

'

$0.15

($0.02)

$0.49

Income (Loss) from Discontinued Operations (in dollars per share)

'

'

'

'

'

'

'

'

$0.11

($0.02)

$0.49

Gain on Disposal of Discontinued Operations (in dollars per share)

'

'

'

'

'

'

'

'

$0.05

$0

$0

Total Income (Loss) From Discontinued Operations (in dollars per share)

'

'

'

'

'

'

'

'

$0.16

($0.02)

$0.49

Black Warrior Basin

'

'

'

'

'

'

'

'

'

'

'

Assets of Disposal Group, Including Discontinued Operation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Accounts receivable

2,829

'

'

'

'

'

'

'

2,829

'

'

Inventories

0

'

'

'

'

'

'

'

0

'

'

Oil and gas properties

0

'

'

'

'

'

'

'

0

'

'

Less accumulated depreciation, depletion and amortization

0

'

'

'

'

'

'

'

0

'

'

Other property, net

0

'

'

'

'

'

'

'

0

'

'

Total assets held-for-sale

2,829

'

'

'

'

'

'

'

2,829

'

'

Liabilities of Disposal Group, Including Discontinued Operation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Accounts payable

-1,732

'

'

'

'

'

'

'

-1,732

'

'

Royalty payable

-550

'

'

'

'

'

'

'

-550

'

'

Other current liabilities

-379

'

'

'

'

'

'

'

-379

'

'

Other long-term liabilities

0

'

'

'

'

'

'

'

0

'

'

Total liabilities held-for-sale

-2,661

'

'

'

'

'

'

'

-2,661

'

'

Total held-for-sale properties

168

'

'

'

'

'

'

'

168

'

'

North Louisiana/East Texas

'

'

'

'

'

'

'

'

'

'

'

Assets of Disposal Group, Including Discontinued Operation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Accounts receivable

1,272

'

'

'

'

'

'

'

1,272

'

'

Inventories

68

'

'

'

'

'

'

'

68

'

'

Oil and gas properties

348,379

'

'

'

'

'

'

'

348,379

'

'

Less accumulated depreciation, depletion and amortization

-301,609

'

'

'

'

'

'

'

-301,609

'

'

Other property, net

165

'

'

'

'

'

'

'

165

'

'

Total assets held-for-sale

48,275

'

'

'

'

'

'

'

48,275

'

'

Liabilities of Disposal Group, Including Discontinued Operation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Accounts payable

-11

'

'

'

'

'

'

'

-11

'

'

Royalty payable

-869

'

'

'

'

'

'

'

-869

'

'

Other current liabilities

-21

'

'

'

'

'

'

'

-21

'

'

Other long-term liabilities

-14,983

'

'

'

'

'

'

'

-14,983

'

'

Total liabilities held-for-sale

-15,884

'

'

'

'

'

'

'

-15,884

'

'

Total held-for-sale properties

$32,391

'

'

'

'

'

'

'

$32,391

'

'

[1]

As discussed in Note 13, Discontinued Operations, during the fourth quarter of 2013, the Company completed the sale of its Black Warrior Basin coalbed methane properties in Alabama. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013. Also, during the third quarter of 2013, the Company classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations.

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	$2,756	$45,515
Regulatory Assets, Noncurrent	84,890	110,566
Regulatory Liability, Current	49,006	45,116
Regulatory Liability, Noncurrent	94,125	80,404
Refundable negative salvage	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	15,800	'
Regulatory Liability, Noncurrent	39,700	'
Gas supply adjustment	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	2,406	42,726
Regulatory Assets, Noncurrent	0	0
Alabama Gas Corporation	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	2,756	45,515
Regulatory Assets, Noncurrent	84,890	110,566
Regulatory Liability, Current	49,006	45,116
Regulatory Liability, Noncurrent	94,125	80,404
Alabama Gas Corporation | RSE adjustment	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	4,690	1,740
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Unbilled service margin	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	28,504	25,078
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Postretirement liabilities	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	26,197	1,237
Alabama Gas Corporation | Refundable negative salvage	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	15,779	18,265
Regulatory Liability, Noncurrent	39,663	53,467
Alabama Gas Corporation | Asset retirement obligation	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	27,528	24,930
Alabama Gas Corporation | Other	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Liability, Current	33	33
Regulatory Liability, Noncurrent	737	770
Alabama Gas Corporation | Pension assets	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	325	170
Regulatory Assets, Noncurrent	58,243	90,708
Alabama Gas Corporation | Accretion and depreciation for asset retirement obligation	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	18,046	16,536
Alabama Gas Corporation | Risk management activities	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	2,593
Regulatory Assets, Noncurrent	0	0
Alabama Gas Corporation | Rate recovery of asset removal costs, net	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	4,601	3,322
Alabama Gas Corporation | Enhanced stability reserve	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	4,000	0
Alabama Gas Corporation | Other	'	'
Regulatory Assets and Liabilities [Line Items]	'	'
Regulatory Assets, Current	25	26
Regulatory Assets, Noncurrent	$0	$0

Transactions_with_Related_Part1

Transactions with Related Parties (Details) (Alabama Gas Corporation, USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Alabama Gas Corporation	'	'	'
Related Party Transaction [Line Items]	'	'	'
Net trade receivables from affiliates	$4,700,000	$5,700,000	'
Interest income from related party	18,000	'	'
Interest expense in affiliated company	'	$300,000	$400,000

Rollforward_of_Accumulated_Oth

Rollforward of Accumulated Other Comprehensive Income (Loss) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'
Balance as of December 31, 2012	($8,311)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	568
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	-12,324
Other Comprehensive Income (Loss), Net of Tax	-11,756
Balance as of December 31, 2013	-20,067
Cash Flow Hedges	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'
Balance as of December 31, 2012	44,196
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	-11,014
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	-21,004
Other Comprehensive Income (Loss), Net of Tax	-32,018
Balance as of December 31, 2013	12,178
Pension and Postretirement Plans	'
Accumulated Other Comprehensive Income (Loss) [Roll Forward]	'
Balance as of December 31, 2012	-52,507
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	11,582
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	8,680
Other Comprehensive Income (Loss), Net of Tax	20,262
Balance as of December 31, 2013	($32,245)

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) Reclassifications of Accumulated Other Comprehensive Income (Details) (USD $)

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenue

$472,733,000

$320,406,000

$471,495,000

$474,016,000

$414,297,000

$276,429,000

$451,904,000

$398,189,000

$1,738,650,000

$1,540,819,000

$1,373,113,000

Interest expense

'

'

'

'

'

'

'

'

-69,200,000

-65,542,000

-44,822,000

Income From Continuing Operations

'

'

'

'

'

'

'

'

193,147,000

255,220,000

224,305,000

Income tax expense

'

'

'

'

'

'

'

'

-105,282,000

-144,534,000

-126,322,000

Pension and postretirement plans:

'

'

'

'

'

'

'

'

'

'

'

Settlement charges

'

64,000

'

500,000

'

'

'

'

'

'

'

Settlement charges expensed

'

18,000

'

100,000

'

'

'

'

'

'

'

Alabama Gas Corporation

'

'

'

'

'

'

'

'

'

'

'

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenue

142,771,000

48,368,000

104,514,000

237,685,000

124,406,000

61,809,000

70,887,000

194,487,000

'

'

'

Interest expense

'

'

'

'

'

'

'

'

-15,649,000

-16,284,000

-14,740,000

Income tax expense

'

'

'

'

'

'

'

'

-34,687,000

-30,244,000

-26,670,000

Pension and postretirement plans:

'

'

'

'

'

'

'

'

'

'

'

Settlements recognized as a pension asset

'

46,000

'

400,000

'

'

'

'

'

'

'

Reclassification out of Accumulated Other Comprehensive Income

'

'

'

'

'

'

'

'

'

'

'

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Net of tax

'

'

'

'

'

'

'

'

12,324,000

'

'

Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income

'

'

'

'

'

'

'

'

'

'

'

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Income From Continuing Operations

'

'

'

'

'

'

'

'

33,961,000

'

'

Income tax expense

'

'

'

'

'

'

'

'

-12,957,000

'

'

Net of tax

'

'

'

'

'

'

'

'

21,004,000

'

'

Pension and Postretirement Plans | Reclassification out of Accumulated Other Comprehensive Income

'

'

'

'

'

'

'

'

'

'

'

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Income From Continuing Operations

'

'

'

'

'

'

'

'

-13,354,000

'

'

Income tax expense

'

'

'

'

'

'

'

'

4,674,000

'

'

Net of tax

'

'

'

'

'

'

'

'

-8,680,000

'

'

Pension and postretirement plans:

'

'

'

'

'

'

'

'

'

'

'

Transition obligation

'

'

'

'

'

'

'

'

-319,000

'

'

Prior service cost

'

'

'

'

'

'

'

'

-257,000

'

'

Actuarial losses

'

'

'

'

'

'

'

'

-12,357,000

[1]

'

'

Actuarial losses on settlement charges

'

'

'

'

'

'

'

'

-421,000

'

'

Commodity Contract | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income

'

'

'

'

'

'

'

'

'

'

'

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenue

'

'

'

'

'

'

'

'

35,684,000

'

'

Interest Rate Swap | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income

'

'

'

'

'

'

'

'

'

'

'

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Interest expense

'

'

'

'

'

'

'

'

($1,723,000)

'

'

[1]

In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million is recognized in actuarial losses above and $0.4 million is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 is recognized in actuarial losses above and $46,000 is recognized as a regulatory asset at Alagasco and reported in actuarial losses on settlement charges above.

Summarized_Quarterly_Financial2

Summarized Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended												12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Selected Quarterly Financial Information [Abstract]	'		'		'		'		'	'	'	'	'	'	'
Adjusted operating revenues	$472,733		$320,406		$471,495		$474,016		$414,297	$276,429	$451,904	$398,189	$1,738,650	$1,540,819	$1,373,113
Oil and gas revenues	0	[1]	0	[1]	-18,562	[1]	-18,663	[1]	-18,749	-18,895	-18,451	-20,255	60,191	76,350	110,366
Operating income (loss)	110,630		-4,052		142,433		102,190		111,609	13,964	215,847	120,494	351,201	461,914	393,699
Income (loss) from continuing operations	63,325		-5,486		80,614		54,694		60,552	-1,505	128,305	67,868	'	'	'
Discontinued operations	0	[1]	0	[1]	-3,871	[1]	-3,146	[1]	-3,557	-5,494	-4,751	16,324	'	'	'
Net Income	84,093		-19,298		83,067		56,692		62,823	2,046	131,287	57,406	204,554	253,562	259,624
Diluted earnings per average common share	'		'		'		'		'	'	'	'	'	'	'
Continuing operations (in dollars per share)	$0.87		($0.08)		$1.11		$0.76		$0.84	($0.02)	$1.77	$0.94	$2.67	$3.53	$3.10
Net income (loss) (in dollars per share)	$1.15		($0.27)		$1.15		$0.78		$0.87	$0.03	$1.82	$0.79	$2.82	$3.51	$3.59
Basic earnings per average common share	'		'		'		'		'	'	'	'	'	'	'
Continuing operations (in dollars per share)	$0.87		($0.08)		$1.12		$0.76		$0.84	($0.02)	$1.78	$0.94	$2.67	$3.54	$3.11
Net income (loss) (in dollars per share)	$1.16		($0.27)		$1.15		$0.79		$0.87	$0.03	$1.82	$0.80	$2.83	$3.52	$3.60
Alabama Gas Corporation	'		'		'		'		'	'	'	'	'	'	'
Selected Quarterly Financial Information [Abstract]	'		'		'		'		'	'	'	'	'	'	'
Adjusted operating revenues	142,771		48,368		104,514		237,685		124,406	61,809	70,887	194,487	'	'	'
Operating income (loss)	34,800		-22,544		2,219		79,293		22,951	-12,743	4,448	78,560	59,081	62,972	59,546
Net Income	19,842		-8,961		-704		47,222		12,197	-10,039	326	46,918	57,399	49,402	46,602
Originally reported	'		'		'		'		'	'	'	'	'	'	'
Selected Quarterly Financial Information [Abstract]	'		'		'		'		'	'	'	'	'	'	'
Adjusted operating revenues	472,733		320,406		490,057		492,679		433,046	295,324	470,355	418,444	'	'	'
Operating income (loss)	$110,630		($4,052)		$146,304		$105,336		$115,166	$19,458	$220,598	$104,170	'	'	'
[1]	As discussed in Note 13, Discontinued Operations, during the fourth quarter of 2013, the Company completed the sale of its Black Warrior Basin coalbed methane properties in Alabama. The property was classified as held-for-sale and reflected in discontinued operations during the third quarter of 2013. Also, during the third quarter of 2013, the Company classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations.

Oil_and_Gas_Operations_Unaudit2

Oil and Gas Operations (Unaudited) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'	'
Proved	$7,043,779	$6,241,148
Unproved	168,975	197,979
Total capitalized costs	7,212,754	6,439,127
Accumulated depreciation, depletion and amortization	2,078,411	1,765,241
Capitalized costs, net	$5,134,343	$4,673,886

Oil_and_Gas_Operations_Unaudit3

Oil and Gas Operations (Unaudited) (Costs Incurred) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property acquisition:	'	'	'
Proved	$4,661	$79,862	$214,993
Unproved	26,820	58,634	91,888
Exploration	435,636	419,284	190,854
Development	655,353	749,256	623,775
Total costs incurred	$1,122,470	$1,307,036	$1,121,510

Oil_and_Gas_Operations_Unaudit4

Oil and Gas Operations (Unaudited) (Results of Operations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'		'		'
Gross revenues	$1,206,293	[1]	$1,090,948	[1]	$834,700	[1]
Production (lifting costs)	351,541		278,193		226,361
Exploration expense	27,942		19,356		12,967
Depreciation, depletion and amortization	449,700		339,569		210,532
Accretion expense	6,995		6,339		5,699
Income tax expense	128,773		160,551		134,564
Results of operations from producing activities	241,342		286,940		244,577
Mark-to-market gain (loss) on derivatives	($47,832)		$58,750		($37,587)
[1]	The years ended December 31, 2013, 2012 and 2011 gross revenues include a pre-tax non-cash mark-to-market loss on derivatives of $47.8 million, a pre-tax non-cash mark-to-market gain on derivatives of $58.8 million and a pre-tax non-cash mark-to-market loss on derivatives of $37.6 million, respectively.

Oil_and_Gas_Operations_Unaudit5

Oil and Gas Operations (Unaudited) (Oil and Gas Operations) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMBoe	MMBoe	MMBoe
Proved Developed and Undeveloped Reserves [Roll Forward]	'	'	'
Proved reserves at beginning of period, total	346.4	343.1	302.9
Revisions of previous estimates, total	4.6	-42.1	-5.8
Purchases, total	0.2	12.4	20.8
Extensions and discoveries, total	36.8	57.1	45.6
Production, total	-25.4	-24.1	-20.4
Sales, total	-14.8	'	'
Proved reserves at end of period, total	347.8	346.4	343.1
Proved developed reserves at end of period (BOE)	259.8	260.5	248.5
Proved undeveloped reserves at end of period (BOE)	88	85.9	94.6
Natural Gas Reserves	'	'	'
Proved Developed and Undeveloped Reserves [Roll Forward]	'	'	'
Proved reserves at beginning of period	809,128	957,368	954,387
Revisions of previous estimates	18,465	-143,704	-12,823
Purchases	282	10,656	19,362
Extensions and discoveries	50,568	61,170	68,160
Production	-70,506	-76,362	-71,718
Sales	-88,212	'	'
Proved reserves at end of period	719,725	809,128	957,368
Proved developed reserves at end of period (volume)	623,305	708,657	788,812
Proved undeveloped reserves at end of period (volume)	96,420	100,471	168,556
Oil Reserves	'	'	'
Proved Developed and Undeveloped Reserves [Roll Forward]	'	'	'
Proved reserves at beginning of period	155,348	129,578	103,262
Revisions of previous estimates	-680	-8,546	-4,513
Purchases	142	7,950	12,583
Extensions and discoveries	20,517	35,132	24,564
Production	-10,378	-8,766	-6,318
Sales	-79	'	'
Proved reserves at end of period	164,870	155,348	129,578
Proved developed reserves at end of period (volume)	113,795	105,976	83,899
Proved undeveloped reserves at end of period (volume)	51,075	49,372	45,679
Natural Gas Liquids Reserves	'	'	'
Proved Developed and Undeveloped Reserves [Roll Forward]	'	'	'
Proved reserves at beginning of period	56,155	53,957	40,601
Revisions of previous estimates	2,211	-9,557	841
Purchases	56	2,569	5,055
Extensions and discoveries	7,823	11,759	9,637
Production	-3,233	-2,573	-2,177
Sales	-1	'	'
Proved reserves at end of period	63,011	56,155	53,957
Proved developed reserves at end of period (volume)	42,087	36,440	33,154
Proved undeveloped reserves at end of period (volume)	20,924	19,715	20,803

Oil_and_Gas_Operations_Unaudit6

Oil and Gas Operations (Unaudited) (Oil and Gas Operations, Activities) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMBoe	MMBoe	MMBoe
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	4.6	-42.1	-5.8
Purchases	0.2	12.4	20.8
Extensions and discoveries	36.8	57.1	45.6
Sales	14.8	'	'
Percentage of undeveloped portion of proved reserves	45.00%	59.00%	69.00%
Percentage of developed portion of proved reserves	55.00%	41.00%	31.00%
Extension Drilling	'	'	'
Reserve Quantities [Line Items]	'	'	'
Extensions and discoveries	21.6	45.6	41.1
Exploratory Drilling	'	'	'
Reserve Quantities [Line Items]	'	'	'
Extensions and discoveries	15.2	11.5	4.5
Price Related Revisions	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	7	'	'
No Longer Expected to be Drilled	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	-5.3	'	'
No Longer Expected to Be Drilled Beyond Five Years	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	-4.6	'	'
Black Warrior Basin	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	'	-5.1	-0.3
Sales	14.8	'	'
Black Warrior Basin | Price Related Revisions	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	'	'	-0.7
Black Warrior Basin | Other Revisions	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	'	'	-0.4
Black Warrior Basin | Change in Year-End Pricing Revisions	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	'	-5.9	'
San Juan Basin	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	2.2	-19.7	-2.6
Extensions and discoveries	2.3	0.9	5.9
Number of well locations	30	6	53
San Juan Basin | Price Related Revisions	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	5.9	'	1.3
San Juan Basin | No Longer Expected to be Drilled	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	-4.6	'	'
San Juan Basin | Change in Year-End Pricing Revisions	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	'	-22.5	'
San Juan Basin | Well Performance	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	'	'	-3.9
Permian Basin	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	-1.2	-15.8	-3.1
Extensions and discoveries	34	56.1	39.6
Number of well locations	262	422	395
Permian Basin | Price Related Revisions	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	0.4	-1	1.4
Permian Basin | No Longer Expected to be Drilled	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	-0.7	'	'

Oil_and_Gas_Operations_Unaudit7

Oil and Gas Operations (Unaudited) (Standardized Measure of Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'	'	'
Deferred hedging gain (loss) excluded from calculation of standardized measure of future net cash flows	$15,000,000	$21,600,000	$74,800,000
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract]	'	'	'
Future gross revenues	19,509,305,000	17,735,363,000	18,196,229,000
Future production costs	6,136,709,000	5,715,248,000	5,823,395,000
Future development costs	1,896,602,000	1,892,600,000	1,539,072,000
Future income tax expense	3,209,697,000	2,809,411,000	3,326,382,000
Future net cash flows	8,266,297,000	7,318,104,000	7,507,380,000
Discount at 10% per annum	4,248,456,000	3,618,785,000	3,878,217,000
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves	4,017,841,000	3,699,319,000	3,629,163,000
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Balance at beginning of year	3,699,319,000	3,629,163,000	2,467,136,000
Revisions to reserves proved in prior years:	'	'	'
Net changes in prices, production costs and future development costs	566,838,000	-922,792,000	707,411,000
Net changes due to revisions in quantity estimates	-81,762,000	-383,755,000	-80,004,000
Development costs incurred, previously estimated	299,432,000	472,603,000	392,720,000
Accretion of discount	369,932,000	362,916,000	246,714,000
Changes in timing and other	-179,502,000	-317,244,000	-25,937,000
Total revisions	974,938,000	-788,272,000	1,240,904,000
New field discoveries and extensions, net of future production and development costs	376,326,000	1,025,419,000	755,977,000
Sales of oil and gas produced, net of production costs	-1,014,593,000	-812,781,000	-763,171,000
Purchases	4,690,000	189,755,000	232,768,000
Sales	-24,876,000	0	0
Net change in income taxes	2,037,000	456,035,000	-304,451,000
Net change in standardized measure of discounted future net cash flows	318,522,000	70,156,000	1,162,027,000
Balance at end of year	$4,017,841,000	$3,699,319,000	$3,629,163,000

Industry_Segment_Information_D

Industry Segment Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
									segment
Segment Reporting Information	'	'	'	'	'	'	'	'	'	'	'
Number of business segments	'	'	'	'	'	'	'	'	2	'	'
Segment Reporting Information, Profit (Loss)	'	'	'	'	'	'	'	'	'	'	'
Total operating revenues	$472,733	$320,406	$471,495	$474,016	$414,297	$276,429	$451,904	$398,189	$1,738,650	$1,540,819	$1,373,113
Operating income (loss) from continuing operations	110,630	-4,052	142,433	102,190	111,609	13,964	215,847	120,494	351,201	461,914	393,699
Depreciation, depletion and amortization expense from continuing operations	'	'	'	'	'	'	'	'	497,381	385,453	253,757
Interest expense	'	'	'	'	'	'	'	'	69,200	65,542	44,822
Income tax expense (benefit) from continuing operations	'	'	'	'	'	'	'	'	105,282	144,534	126,322
Capital expenditures	'	'	'	'	'	'	'	'	1,193,514	1,363,080	1,189,436
Identifiable assets	6,622,212	'	'	'	6,175,890	'	'	'	6,622,212	6,175,890	5,237,416
Property, plant and equipment, net	6,003,638	'	'	'	5,541,636	'	'	'	6,003,638	5,541,636	4,620,776
Oil and Gas Operations	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'	'	'	'	'	'	'	'	'
Oil and gas operations	'	'	'	'	'	'	'	'	1,205,312	1,089,230	838,160
Operating income (loss) from continuing operations	'	'	'	'	'	'	'	'	257,963	369,765	308,561
Depreciation, depletion and amortization expense from continuing operations	'	'	'	'	'	'	'	'	453,474	343,183	213,841
Interest expense	'	'	'	'	'	'	'	'	53,981	49,958	30,907
Income tax expense (benefit) from continuing operations	'	'	'	'	'	'	'	'	71,290	115,090	100,700
Capital expenditures	'	'	'	'	'	'	'	'	1,104,745	1,291,211	1,115,452
Identifiable assets	5,379,135	'	'	'	4,975,170	'	'	'	5,379,135	4,975,170	4,046,242
Property, plant and equipment, net	5,116,958	'	'	'	4,697,683	'	'	'	5,116,958	4,697,683	3,806,787
Natural Gas Distribution	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'	'	'	'	'	'	'	'	'
Natural gas distribution	'	'	'	'	'	'	'	'	533,338	451,589	534,953
Operating income (loss) from continuing operations	'	'	'	'	'	'	'	'	93,768	93,216	86,216
Depreciation, depletion and amortization expense from continuing operations	'	'	'	'	'	'	'	'	43,907	42,270	39,916
Interest expense	'	'	'	'	'	'	'	'	15,649	16,284	14,740
Income tax expense (benefit) from continuing operations	'	'	'	'	'	'	'	'	34,687	30,244	26,670
Capital expenditures	'	'	'	'	'	'	'	'	88,769	71,869	73,984
Identifiable assets	1,193,413	'	'	'	1,177,134	'	'	'	1,193,413	1,177,134	1,163,959
Property, plant and equipment, net	885,550	'	'	'	842,685	'	'	'	885,550	842,685	813,471
Eliminations and other	'	'	'	'	'	'	'	'	'	'	'
Segment Reporting Information, Profit (Loss)	'	'	'	'	'	'	'	'	'	'	'
Operating income (loss) from continuing operations	'	'	'	'	'	'	'	'	-530	-1,067	-1,078
Interest expense	'	'	'	'	'	'	'	'	-430	-700	-825
Income tax expense (benefit) from continuing operations	'	'	'	'	'	'	'	'	-695	-800	-1,048
Identifiable assets	49,664	'	'	'	23,586	'	'	'	49,664	23,586	27,215
Property, plant and equipment, net	$1,130	'	'	'	$1,268	'	'	'	$1,130	$1,268	$518

Schedule_II_Valuation_and_Qual1

Schedule II - Valuation and Qualifying Accounts (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
ALLOWANCE FOR DOUBTFUL ACCOUNTS	'	'	'
Balance at beginning of year	$6,549	$12,946	$15,048
Charged to income	2,244	1,415	4,269
Recoveries and adjustments	-1,463	-1,262	-1,744
Net additions	781	153	2,525
Less uncollectible accounts written off	-1,636	-6,550	-4,627
Balance at end of year	5,694	6,549	12,946
Alabama Gas Corporation	'	'	'
ALLOWANCE FOR DOUBTFUL ACCOUNTS	'	'	'
Balance at beginning of year	5,700	12,100	14,200
Charged to income	2,243	1,409	4,202
Recoveries and adjustments	-1,469	-1,263	-1,745
Net additions	774	146	2,457
Less uncollectible accounts written off	-1,474	-6,546	-4,557
Balance at end of year	$5,000	$5,700	$12,100