10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

____________________________________________

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2013

OR

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

Commission File Number	Registrant	State of Incorporation	IRS Employer Identification Number
1-7810	Energen Corporation	Alabama	63-0757759
2-38960	Alabama Gas Corporation	Alabama	63-0022000

605 Richard Arrington Jr. Boulevard North

Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

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

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

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

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

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

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

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

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

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

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

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of November 1, 2013.

Energen Corporation	$0.01 par value	72,685,415 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2013

TABLE OF CONTENTS

		Page
PART I: FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	(a) Consolidated Condensed Statements of Income of Energen Corporation	3
	(b) Consolidated Condensed Statements of Comprehensive Income of Energen Corporation	4
	(c) Consolidated Condensed Balance Sheets of Energen Corporation	5
	(d) Consolidated Condensed Statements of Cash Flows of Energen Corporation	7
	(e) Condensed Statements of Income of Alabama Gas Corporation	8
	(f) Condensed Balance Sheets of Alabama Gas Corporation	9
	(g) Condensed Statements of Cash Flows of Alabama Gas Corporation	11
	(h) Notes to Unaudited Condensed Financial Statements	12
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
	Selected Business Segment Data of Energen Corporation	40
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42
Item 4.	Controls and Procedures	43
PART II: OTHER INFORMATION
Item 1.	Legal Proceedings	44
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 6.	Exhibits	44
SIGNATURES		45

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except per share data)	2013			2012			2013			2012
Operating Revenues
Oil and gas operations	$	272,038		$	214,620		$	875,350		$	799,339
Natural gas distribution	48,368			61,809			390,567			327,183
Total operating revenues	320,406			276,429			1,265,917			1,126,522
Operating Expenses
Cost of gas	20,435			20,924			163,448			94,179
Operations and maintenance	141,271			123,730			413,401			336,568
Depreciation, depletion and amortization	136,123			96,634			365,355			276,465
Taxes, other than income taxes	24,858			19,572			77,955			64,314
Accretion expense	1,771			1,605			5,187			4,691
Total operating expenses	324,458			262,465			1,025,346			776,217
Operating Income (Loss)	(4,052		)	13,964			240,571			350,305
Other Income (Expense)
Interest expense	(17,689		)	(17,195		)	(51,751		)	(48,447		)
Other income	13,062			1,488			15,578			3,678
Other expense	(434		)	(84		)	(631		)	(305		)
Total other expense	(5,061		)	(15,791		)	(36,804		)	(45,074		)
Income (Loss) From Continuing Operations Before Income Taxes	(9,113		)	(1,827		)	203,767			305,231
Income tax expense (benefit)	(3,627		)	(322		)	73,897			110,508
Income (Loss) From Continuing Operations	(5,486		)	(1,505		)	129,870			194,723
Discontinued Operations, net of taxes
Income (loss) from discontinued operations	1,866			3,551			6,269			(3,984		)
Loss on disposal of discontinued operations	(15,678		)	—			(15,678		)	—
Income (Loss) From Discontinued Operations	(13,812		)	3,551			(9,409		)	(3,984		)
Net Income (Loss)	$	(19,298	)	$	2,046		$	120,461		$	190,739
Diluted Earnings Per Average Common Share
Continuing Operations	$	(0.08	)	$	(0.02	)	$	1.80		$	2.69
Discontinued operations	(0.19		)	0.05			(0.13		)	(0.05		)
Net Income (Loss)	$	(0.27	)	$	0.03		$	1.67		$	2.64
Basic Earnings Per Average Common Share
Continuing Operations	$	(0.08	)	$	(0.02	)	$	1.80		$	2.70
Discontinued operations	(0.19		)	0.05			(0.13		)	(0.06		)
Net Income (Loss)	$	(0.27	)	$	0.03		$	1.67		$	2.64
Dividends Per Common Share	$	0.145		$	0.140		$	0.435		$	0.420
Diluted Average Common Shares Outstanding	72,346			72,316			72,272			72,301
Basic Average Common Shares Outstanding	72,346			72,130			72,220			72,121

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

3

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Net Income (Loss)	$	(19,298	)	$	2,046		$	120,461		$	190,739
Other comprehensive income (loss):
Cash flow hedges:
Current period change in fair value of commodity derivative instruments, net of tax of $42, ($30,622), ($6,669) and $30,621	69			(49,962		)	(10,882		)	49,961
Reclassification adjustment for commodity derivative instruments, net of tax of ($3,205), ($4,924), ($11,486) and ($14,303)	(5,229		)	(8,034		)	(18,740		)	(23,337		)
Current period change in fair value of interest rate swap, net of tax of ($188), ($375), ($23) and ($1,205)	(350		)	(697		)	(42		)	(2,240		)
Reclassification adjustment for interest rate swap, net of tax of $156, $142, $449 and $422	290			263			833			783
Total cash flow hedges	(5,220		)	(58,430		)	(28,831		)	25,167
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $26, $25, $77 and $75	48			47			143			140
Amortization of prior service cost, net of taxes of $28, $30, $82 and $89	51			55			153			166
Amortization of net loss, including settlement charges, net of taxes of $729, $413, $2,383 and $1,238	1,354			766			4,425			2,300
Current period change in fair value of pension and postretirement plans, net of taxes of $2,238, ($4,073), $2,238 and ($4,073)	4,157			(7,564		)	4,157			(7,564		)
Total pension and postretirement plans	5,610			(6,696		)	8,878			(4,958		)
Comprehensive Income (Loss)	$	(18,908	)	$	(63,080	)	$	100,508		$	210,948

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

4

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	September 30, 2013		December 31, 2012
ASSETS
Current Assets
Cash and cash equivalents	$	12,413	$	9,704
Accounts receivable, net of allowance for doubtful accounts of $6,070 at September 30, 2013, and $6,549 at December 31, 2012	200,043		277,900
Inventories
Storage gas inventory	39,507		32,205
Materials and supplies	19,187		28,291
Liquified natural gas in storage	2,990		3,498
Regulatory asset	11,213		45,515
Income tax receivable	7,653		6,664
Assets held for sale	183,862		—
Deferred income taxes	42,722		8,520
Prepayments and other	12,996		12,823
Total current assets	532,586		425,120
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,655,343		6,439,127
Less accumulated depreciation, depletion and amortization	1,657,682		1,765,241
Oil and gas properties, net	4,997,661		4,673,886
Utility plant	1,471,174		1,416,590
Less accumulated depreciation	594,604		573,947
Utility plant, net	876,570		842,643
Other property, net	29,733		25,107
Total property, plant and equipment, net	5,903,964		5,541,636
Other Assets
Regulatory asset	89,004		110,566
Other postretirement assets	17,417		1,404
Long-term derivative instruments	12,786		40,577
Deferred charges and other	59,115		56,587
Total other assets	178,322		209,134
TOTAL ASSETS	$	6,614,872	$	6,175,890

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

5

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands, except share and per share data)	September 30, 2013			December 31, 2012
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	125,000		$	50,000
Notes payable to banks	901,000			643,000
Accounts payable	256,109			257,579
Accrued taxes	51,878			30,076
Customers’ deposits	20,531			24,705
Amounts due customers	19,974			19,718
Accrued wages and benefits	25,896			24,984
Regulatory liability	40,168			45,116
Royalty payable	49,976			34,426
Liabilities related to assets held for sale	23,945			—
Other	26,812			30,178
Total current liabilities	1,541,289			1,159,782
Long-term debt	1,028,509			1,103,528
Deferred Credits and Other Liabilities
Asset retirement obligation	106,604			118,023
Pension and other postretirement liabilities	90,893			110,282
Regulatory liability	81,414			80,404
Long-term derivative instruments	1,961			11,305
Deferred income taxes	979,898			905,601
Other	14,638			10,275
Total deferred credits and other liabilities	1,275,408			1,235,890
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized	—			—
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized, 75,485,159 shares issued at September 30, 2013, and 75,067,760 shares issued at December 31, 2012	755			751
Premium on capital stock	514,784			492,108
Capital surplus	2,802			2,802
Retained earnings	2,403,062			2,314,055
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	16,730			46,352
Pension and postretirement plans	(43,629		)	(52,507		)
Interest rate swap	(1,365		)	(2,156		)
Deferred compensation plan	3,319			2,774
Treasury stock, at cost: 2,977,920 shares at September 30, 2013, and 2,998,620 shares at December 31, 2012	(126,792		)	(127,489		)
Total shareholders’ equity	2,769,666			2,676,690
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,614,872		$	6,175,890

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

6

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Nine months ended September 30, (in thousands)	2013			2012
Operating Activities
Net income	$	120,461		$	190,739
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	392,854			300,863
Asset impairment	24,612			21,545
Accretion expense	6,131			5,581
Deferred income taxes	51,682			80,724
Bad debt expense	1,203			370
Exploratory expense	8,759			11,420
Change in derivative fair value	53,581			(34,469		)
Gain on sale of assets	(10,980		)	(420		)
Stock based compensation expense	11,759			6,820
Other, net	25,455			10,779
Net change in:
Accounts receivable	50,767			57,334
Inventories	1,169			62
Accounts payable	(74,183		)	(12,562		)
Amounts due customers, including gas supply pass-through	36,891			(52,466		)
Income tax receivable	(989		)	1,817
Pension and other postretirement benefit contributions	(11,332		)	(5,056		)
Other current assets and liabilities	40,176			20,038
Net cash provided by operating activities	728,016			603,119
Investing Activities
Additions to property, plant and equipment	(961,798		)	(898,202		)
Acquisitions, net of cash acquired	(21,400		)	(104,200		)
Proceeds from sale of assets	16,220			2,420
Other, net	(1,210		)	(746		)
Net cash used in investing activities	(968,188		)	(1,000,728		)
Financing Activities
Payment of dividends on common stock	(31,454		)	(30,292		)
Issuance of common stock	13,680			1,164
Payment of long-term debt	(55		)	(1,143		)
Net change in short-term debt	258,000			465,000
Tax benefit on stock compensation	2,710			514
Other	—			(38		)
Net cash provided by financing activities	242,881			435,205
Net change in cash and cash equivalents	2,709			37,596
Cash and cash equivalents at beginning of period	9,704			9,541
Cash and Cash Equivalents at End of Period	$	12,413		$	47,137

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

7

CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Operating Revenues	$	48,368		$	61,809		$	390,567		$	327,183
Operating Expenses
Cost of gas	20,435			20,924			163,448			94,179
Operations and maintenance	33,650			37,235			107,672			107,470
Depreciation and amortization	11,063			10,572			32,665			31,551
Income taxes
Current	(7,703		)	(9,242		)	16,440			13,567
Deferred	2,093			3,264			6,448			9,431
Taxes, other than income taxes	5,764			5,821			27,814			23,718
Total operating expenses	65,302			68,574			354,487			279,916
Operating Income (Loss)	(16,934		)	(6,765		)	36,080			47,267
Other Income (Expense)
Allowance for funds used during construction	184			187			630			452
Other income	12,092			787			13,203			1,925
Other expense	(434		)	(84		)	(623		)	(254		)
Total other income	11,842			890			13,210			2,123
Interest Expense
Interest on long-term debt	3,377			3,423			10,133			10,270
Other interest expense	492			741			1,600			1,915
Total interest expense	3,869			4,164			11,733			12,185
Net Income (Loss)	$	(8,961	)	$	(10,039	)	$	37,557		$	37,205

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

8

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	September 30, 2013			December 31, 2012
ASSETS
Property, Plant and Equipment
Utility plant	$	1,471,174		$	1,416,590
Less accumulated depreciation	594,604			573,947
Utility plant, net	876,570			842,643
Other property, net	41			42
Current Assets
Cash and cash equivalents	8,541			5,559
Accounts receivable
Gas	39,962			94,011
Other	4,655			5,117
Affiliated companies	6,579			5,742
Allowance for doubtful accounts	(5,300		)	(5,700		)
Inventories
Storage gas inventory	39,507			32,205
Materials and supplies	5,401			5,528
Liquified natural gas in storage	2,990			3,498
Regulatory asset	11,213			45,515
Income tax receivable	1,601			2,762
Deferred income taxes	22,314			18,799
Prepayments and other	6,595			4,451
Total current assets	144,058			217,487
Other Assets
Regulatory asset	89,004			110,566
Pension and other postretirement assets	13,399			848
Deferred charges and other	10,994			11,290
Total other assets	113,397			122,704
TOTAL ASSETS	$	1,134,066		$	1,182,876

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

9

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands, except share data)	September 30, 2013		December 31, 2012
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized	$	—	$	—
Common shareholder’s equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at September 30, 2013 and December 31, 2012	20		20
Premium on capital stock	31,682		31,682
Capital surplus	2,802		2,802
Retained earnings	330,234		325,999
Total common shareholder’s equity	364,738		360,503
Long-term debt	249,973		250,028
Total capitalization	614,711		610,531
Current Liabilities
Notes payable to banks	49,000		77,000
Accounts payable	32,997		51,741
Accrued taxes	28,635		24,186
Customers’ deposits	20,531		24,705
Amounts due customers	19,974		19,718
Accrued wages and benefits	8,154		6,703
Regulatory liability	40,168		45,116
Other	9,293		9,018
Total current liabilities	208,752		258,187
Deferred Credits and Other Liabilities
Deferred income taxes	199,372		189,381
Pension and other postretirement liabilities	28,371		43,611
Regulatory liability	81,414		80,404
Other	1,446		762
Total deferred credits and other liabilities	310,603		314,158
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,134,066	$	1,182,876

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

10

CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Nine months ended September 30, (in thousands)	2013			2012
Operating Activities
Net income	$	37,557		$	37,205
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	32,665			31,551
Deferred income taxes	6,448			9,431
Bad debt expense	1,120			364
Gain on sale of assets	10,889			—
Other, net	1,524			4,681
Net change in:
Accounts receivable	19,801			29,539
Inventories	(6,667		)	5,975
Accounts payable	(16,181		)	(17,222		)
Amounts due customers, including gas supply pass-through	36,891			(52,466		)
Income tax receivable	1,161			6,002
Pension and other postretirement benefit contributions	(5,848		)	(2,044		)
Other current assets and liabilities	(112		)	(9,795		)
Net cash provided by operating activities	119,248			43,221
Investing Activities
Additions to property, plant and equipment	(67,085		)	(49,746		)
Proceeds from sale of assets	13,838			—
Other, net	(1,642		)	2,490
Net cash used in investing activities	(54,889		)	(47,256		)
Financing Activities
Dividends	(33,322		)	(28,182		)
Payment of long-term debt	(55		)	(143		)
Net increases in advances from affiliates	—			24,867
Net change in short-term debt	(28,000		)	10,000
Other	—			(38		)
Net cash provided by (used in) financing activities	(61,377		)	6,504
Net change in cash and cash equivalents	2,982			2,469
Cash and cash equivalents at beginning of period	5,559			7,817
Cash and Cash Equivalents at End of Period	$	8,541		$	10,286

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

11

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

1. BASIS OF PRESENTATION

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2012, 2011 and 2010, included in the 2012 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

On December 31, 2012, the Company and Alagasco revised the presentation of outstanding checks in its financial statements to reflect outstanding checks as a reduction in cash as of the date the checks were released for payment. The effect of not revising the presentation of cash balances for the nine months ended September 30, 2012 resulted in an increase of $1.9 million and a decrease of $0.8 million to Energen and Alagasco’s operating cash flows, respectively. The Company and Alagasco determined that the amounts were not material to the respective statements of cash flows. This adjustment had no impact on Energen or Alagasco’s statements of income.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. The Company’s current RSE order had an original term extending through December 31, 2014. At its meeting on November 5, 2013, the APSC voted to make certain RSE modifications effective January 1, 2014, which are described as follows. The term of the order is extended through September 30, 2018. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted will be 56.5 percent with Alagasco allowed to budget at the cap. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to operations and maintenance (O&M) expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from a 2007 base year, adjusted for inflation using the Index Range.  Alagasco expects these modifications to be included in a final written order in the fourth quarter of 2013.

Alagasco’s current allowed range of return on average common equity is 13.15 percent to 13.65 percent through December 31, 2013. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and nine months ended September 30, 2013, Alagasco had a net $4.3 million pre-tax and a net $10.6 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Additionally, during the three months and nine months ended September 30, 2013, Alagasco had a $10.9 million reduction in revenues related to the sale of its Metro Operations Center in August 2013. During the three months and nine months ended September 30, 2012, Alagasco had a net $1.3 million and a net $6.3 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $7.8 million and a $13.0 million annual increase in revenues became effective December 1, 2012 and 2011, respectively.

RSE currently limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Currently, under the inflation-based CCM established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the September Index Range on a rate year basis, no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the

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base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2013 and 2012.

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

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

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

3. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company recognizes all derivatives on the balance sheet and measures all derivatives at fair value. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at September 30, 2013. The largest counterparty net loss position at September 30, 2013, Morgan Stanley Capital Group, constituted approximately $19.8 million of Energen Resources’ total net loss on fair value of derivatives. At September 30, 2013, Energen Resources was in a net gain position with Macquarie Bank Limited for approximately $10.0 million.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in operating revenues immediately. All other derivative transactions not previously qualified for cash flow hedge accounting are still considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These derivatives are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive

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income until the forecasted transactions actually occur.  Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.

Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 will be accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.

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

(in thousands)	September 30, 2013
	Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	53,082			$	—	$	53,082
Long-term asset derivative instruments	18,346				—		18,346
Total derivative assets	71,428				—		71,428
Accounts receivable	(40,789		)	*	—		(40,789		)
Long-term asset derivative instruments	(5,560		)	*	—		(5,560		)
Accounts payable	(31,928		)		—		(31,928		)
Long-term liability derivative instruments	(1,379		)		—		(1,379		)
Total derivative liabilities	(79,656		)		—		(79,656		)
Total derivatives not designated	$	(8,228	)		$	—	$	(8,228	)

(in thousands)	December 31, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	87,514			$	—		$	87,514
Long-term asset derivative instruments	37,954				—			37,954
Total derivative assets	125,468				—			125,468
Accounts receivable	(37,326		)	*	—			(37,326		)
Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
Long-term liability derivative instruments	(8,726		)		—			(8,726		)
Total derivative liabilities	(52,862		)		—			(52,862		)
Total derivatives designated	72,606				—			72,606
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,604				—			14,604
Long-term asset derivative instruments	9,433				—			9,433
Total derivative assets	24,037				—			24,037
Accounts payable	—				(2,593		)	(2,593		)
Long-term liability derivative instruments	(874		)		—			(874		)
Total derivative liabilities	(874		)		(2,593		)	(3,467		)
Total derivatives not designated	23,163				(2,593		)	20,570
Total derivatives	$	95,769			$	(2,593	)	$	93,176

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

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The Company had a net $10.3 million and a net $28.4 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of September 30, 2013, and December 31, 2012, respectively.

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

(in thousands)	Location on Statement of Income	Three months ended September 30, 2013			Three months ended September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of $42 and ($30,622)	—	$	69		$	(49,962	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	8,455		$	15,998
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(22	)	$	(3,042	)

(in thousands)	Location on Statement of Income	Nine months ended September 30, 2013			Nine months ended September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of ($6,669) and $30,621	—	$	(10,882	)	$	49,961
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	29,391		$	39,012
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	835		$	(1,372	)

The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:

(in thousands)	Location on Statement of Income	Three months ended September 30, 2013			Three months ended September 30, 2012
Loss recognized in income on derivatives	Operating revenues	$	(92,313	)	$	(45,618	)

(in thousands)	Location on Statement of Income	Nine months ended September 30, 2013			Nine months ended September 30, 2012
Gain (loss) recognized in income on derivatives	Operating revenues	$	(70,735	)	$	33,825

As of September 30, 2013, $13.1 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of September 30, 2013, the Company had 13.5 billion cubic feet (Bcf), 51.8 Bcf and 6.0 Bcf of natural gas hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 4.4 million barrels (MMBbl), 9.8 MMBbl and 5.8 MMBbl of oil and oil basis hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 11.9 million gallons (MMgal) and 1.9 MMgal of natural gas liquid hedges which expire during 2013 and 2014, respectively, that are considered mark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $6.7 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being held for sale.

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Energen Resources entered into the following transactions for the remainder of 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	3.0	Bcf	$4.82 Mcf	NYMEX Swaps
	8.9	Bcf	$4.51 Mcf	Basin Specific Swaps - San Juan
	1.6	Bcf	$3.64 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	6.0	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
Oil
2013	2,434	MBbl	$91.44 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	5,760	MBbl	$88.85 Bbl	NYMEX Swaps
Oil Basis Differential
2013	907	MBbl	$(2.99) Bbl	WTS/WTI Basis Swaps*
	1,070	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	12.0	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

As of September 30, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010. 

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

	September 30, 2013
(in thousands)	Level 2*			Level 3*		Total
Current assets	$	(12,712	)	$	25,005	$	12,293
Noncurrent assets	6,828			5,958		12,786
Current liabilities	(40,970		)	9,042		(31,928		)
Noncurrent liabilities	(2,580		)	1,201		(1,379		)
Net derivative asset (liability)	$	(49,434	)	$	41,206	$	(8,228	)

	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.

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As of September 30, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which were classified as Level 2 fair values and included in the above table as current liabilities. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012.

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $22 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $22 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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

	Three months ended			Three months ended
(in thousands)	September 30, 2013			September 30, 2012
Balance at beginning of period	$	51,131		$	103,456
Realized gains	10,852			18,737
Unrealized losses relating to instruments held at the reporting date*	(10,947		)	(46,983		)
Settlements during period	(9,830		)	(17,929		)
Balance at end of period	$	41,206		$	57,281

	Nine months ended			Nine months ended
(in thousands)	September 30, 2013			September 30, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	41,952			51,858
Unrealized losses relating to instruments held at the reporting date*	(48,835		)	(9,328		)
Settlements during period	(40,930		)	(51,050		)
Balance at end of period	$	41,206		$	57,281

*Includes $0.8 million and $4.7 million in mark-to-market gains for the three months and nine months ended September 30, 2013, respectively. Includes $7.9 million and $4.5 million in mark-to-market losses for the three months and nine months ended September 30, 2012, respectively.

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

(in thousands)	Fair Value as of September 30, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	9,499		Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf
2014	$	27,678		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
2015	$	1,201		Discounted Cash Flow	Forward Basis	($0.20) Mcf
Natural Gas Basis - Permian
2013	$	286		Discounted Cash Flow	Forward Basis	($0.14) Mcf
2014	$	825		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2013	$	(1,897	)	Discounted Cash Flow	Forward Basis	($1.06) Bbl
Oil Basis - WTI/WTI
2013	$	(641	)	Discounted Cash Flow	Forward Basis	($0.41 - $0.50) Bbl
Natural Gas Liquids
2013	$	4,255		Discounted Cash Flow	Forward Price	$0.74 - $0.81 Gal

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

The tables below set forth information about the offsetting of derivative assets and liabilities as follows:

	September 30, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	71,428	$	(46,349	)	$	25,079	$	—	$	—	$	25,079
Derivative liabilities	$	79,656	$	(46,349	)	$	33,307	$	—	$	—	$	33,307

	December 31, 2012
								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

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4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended							Three months ended
(in thousands, except per share amounts)	September 30, 2013							September 30, 2012
	Net				Per Share			Net			Per Share
	Loss			Shares	Amount			Income		Shares	Amount
Basic EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,130	$	0.03
Effect of dilutive securities
Stock options				—						183
Non-vested restricted stock				—						3
Diluted EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,316	$	0.03

In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 242,560 of excluded shares for the three months ended September 30, 2013.

	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2013					September 30, 2012
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	120,461	72,220	$	1.67	$	190,739	72,121	$	2.64
Effect of dilutive securities
Stock options			41					177
Non-vested restricted stock			10					3
Performance share awards			1					—
Diluted EPS	$	120,461	72,272	$	1.67	$	190,739	72,301	$	2.64

The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive:

	Three months ended September 30,		Nine months ended September 30,
(in thousands)	2013	2012	2013	2012
Stock options	—	850	875	850
Performance share awards	—	—	79	—

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5. SEGMENT INFORMATION

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

	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Operating revenues from continuing operations
Oil and gas operations	$	272,038		$	214,620		$	875,350		$	799,339
Natural gas distribution	48,368			61,809			390,567			327,183
Total	$	320,406		$	276,429		$	1,265,917		$	1,126,522
Operating income (loss) from continuing operations
Oil and gas operations	$	18,607		$	26,913		$	181,948		$	280,897
Natural gas distribution	(22,544		)	(12,743		)	58,968			70,265
Eliminations and corporate expenses	(115		)	(206		)	(345		)	(857		)
Total	$	(4,052	)	$	13,964		$	240,571		$	350,305
Other income (expense)
Oil and gas operations	$	(13,209	)	$	(12,703	)	$	(38,686	)	$	(35,402	)
Natural gas distribution	7,973			(3,274		)	1,477			(10,062		)
Eliminations and other	175			186			405			390
Total	$	(5,061	)	$	(15,791	)	$	(36,804	)	$	(45,074	)
Income (loss) from continuing operations before income taxes	$	(9,113	)	$	(1,827	)	$	203,767		$	305,231

(in thousands)	September 30, 2013		December 31, 2012
Identifiable assets
Oil and gas operations	$	5,444,672	$	4,975,170
Natural gas distribution	1,127,487		1,177,134
Eliminations and other	42,713		23,586
Total	$	6,614,872	$	6,175,890

6. STOCK COMPENSATION

Stock Incentive Plan

Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, restricted stock, performance shares or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 134,076 non-qualified option shares during the first quarter of 2013 with a grant-date fair value of $16.66.

Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted stock. In January 2013, 46,121 shares of restricted stock were awarded with a grant date fair value of $48.36. These awards were valued based on the quoted market price of the Company’s common stock at the date of grant and have a three year vesting period.

Performance Share Awards: The Stock Incentive Plan also provides for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Company common stock. Performance share awards are valued in a Monte Carlo model which uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. The Company granted 84,311 performance share awards during the first quarter of 2013 with a two year vesting period and a grant-date fair value of $59.19. The Company also

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granted 80,395 performance share awards during the first quarter of 2013 with a three year award period and a grant-date fair value of $60.81.

Stock Appreciation Rights Plan

The Energen Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 88,000 awards during the first quarter of 2013. These awards had a fair value of $39.10 as of September 30, 2013.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During the first quarter of 2013, Energen Resources awarded 33,796 Petrotech units with a fair value of $75.67 as of September 30, 2013, none of which included a market condition. Also awarded were 52,768 Petrotech units which included a market condition and had a fair value of $133.58 as of September 30, 2013. These awards have a three-year vesting period. During the third quarter of 2013, Energen Resources awarded 5,854 Petrotech units with a three-year vesting period and a fair value of $75.67 as of September 30, 2013, and 2,952 Petrotech units with a seventeen-month vesting period and a fair value of $75.88 as of September 30, 2013, none of which included a market condition.

Stock Repurchase Program

During the three months and nine months ended September 30, 2013, the Company had noncash purchases of approximately $0.8 million and $0.9 million, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

7. EMPLOYEE BENEFIT PLANS

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	3,602		$	2,632		$	10,806		$	7,895
Interest cost	2,725			2,700			8,161			8,101
Expected long-term return on assets	(3,713		)	(3,563		)	(11,139		)	(10,689		)
Actuarial loss	3,597			2,099			10,962			6,297
Prior service cost amortization	123			129			367			388
Settlement charge	17			—			161			—
Net periodic expense	$	6,351		$	3,997		$	19,318		$	11,992

There are no required contributions to the qualified pension plans during 2013. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $9.0 million to the qualified pension plans in January 2013. No additional discretionary contributions are expected to be made to the pension plans during 2013. During 2014, the Company may make discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. For the three months and nine months ending September 30, 2013, the Company made benefit payments aggregating $0.2 million and $1.1 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $36,000 through the remainder of 2013. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was expensed and $46,000 was recognized as a pension and postretirement asset in regulatory assets at Alagasco.

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	444		$	463		$	1,333		$	1,390
Interest cost	869			1,062			2,605			3,186
Expected long-term return on assets	(1,242		)	(1,109		)	(3,727		)	(3,328		)
Actuarial loss	—			9			—			27
Transition amortization	324			479			973			1,438
Net periodic expense	$	395		$	904		$	1,184		$	2,713

For the three months and nine months ended September 30, 2013, the Company made contributions aggregating $0.4 million and $1.2 million to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $0.4 million to the postretirement benefit plans through the remainder of 2013.

8. COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 7.5 million barrels of oil equivalent (MMBOE) through September 2017.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources’ total resulting exposure could be as much as $14 million depending on the contractor’s ability to remarket the drilling rig.

Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $185 million through September 2024. During both the nine months ending September 30, 2013 and 2012, Alagasco recognized approximately $36.8 million of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 146 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through October 2014 and an aggregate purchase price of $0.8 million with a market value of $0.8 million.

Income Taxes: The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards.  In accordance with Accounting Standards Codification 740-30-25-7, the Company has not recognized a deferred tax liability for the difference between the book basis and the tax basis in the stock of its subsidiaries. The unrecorded gross outside basis difference for Alagasco exceeds the recorded inside asset basis difference by approximately $35 million and would result in an additional deferred tax liability of $13 million.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered

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material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability.

Energen Resources previously disclosed an adverse judgment relating to the ownership of the company operated Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas.  Upon a Motion to Reconsider, the adverse judgment was vacated by the District Court in Ward County, Texas and a Summary Judgment Order dated July 30, 2013 was entered confirming Energen Resources’ superior title to the Cadenhead Well and its associated oil and gas leases.  The Summary Judgment Order has been appealed by the other party.

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

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $1.8 million of which $1.6 million has been incurred and $0.2 million has been reserved.

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the United States Environmental Protection Agency (EPA), Alagasco and the current site owner. In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the EPA’s investigation of a site which it refers to as the 35th Avenue Superfund Site located in Birmingham, Jefferson County, Alabama.  The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35th Avenue Superfund Site. In September 2013, Alagasco received from EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site.  The letter identifies Alagasco as a potentially responsible party (PRP) under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site.  The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination.  Alagasco has requested additional information from EPA regarding its designation as a PRP, and an opportunity to discuss this designation further with EPA. Alagasco is unable to determine the extent, if any, of its potential liability with respect to the proposed removal action and no amount has been accrued as of September 30, 2013.

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

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2013.

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9. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, was approximately $1,188.2 million and $1,255.8 million and both had a carrying value of $1,154.0 million at September 30, 2013 and December 31, 2012, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $262.8 million and $284.7 million and both had a carrying value of $250.0 million at September 30, 2013 and December 31, 2012, respectively. The fair values are based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company’s interest rate swap was a $2.1 million and a $3.3 million liability at September 30, 2013 and December 31, 2012, respectively, and is classified as Level 2 fair value liability. The fair value of the Company’s interest rate swap is recognized on a gross basis on the consolidated balance sheet.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2013 and December 31, 2012, Alagasco’s finance receivable totaled $10.8 million and $10.7 million, respectively. These finance receivables currently have an average balance of approximately $3,000 with terms of up to 84 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. Uncollected finance receivables are written off approximately 15 months after the account has been final billed. Alagasco had finance receivables past due 90 days or more of $0.7 million and $0.5 million as of September 30, 2013 and December 31, 2012, respectively.

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

(in thousands)
Allowance for credit losses as of December 31, 2012	$	470
Provision	191
Allowance for credit losses as of September 30, 2013	$	661

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10. REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	September 30, 2013				December 31, 2012
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension assets	$	263	$	69,249	$	170	$	90,708
Accretion and depreciation for asset retirement obligation	—		17,579		—		16,536
Risk management activities	—		—		2,593		—
Rate recovery of asset removal costs, net	—		2,176		—		3,322
Gas supply adjustment	10,925		—		42,726		—
Other	25		—		26		—
Total regulatory assets	$	11,213	$	89,004	$	45,515	$	110,566
Regulatory liabilities:
RSE adjustment	$	6,573	$	—	$	1,740	$	—
Unbilled service margin	6,351		—		25,078		—
Postretirement liabilities	—		13,951		—		1,237
Refundable negative salvage	16,321		40,946		18,265		53,467
Gain on sale of property	10,890		—		—		—
Asset retirement obligation	—		25,772		—		24,930
Other	33		745		33		770
Total regulatory liabilities	$	40,168	$	81,414	$	45,116	$	80,404

11. ASSET RETIREMENT OBLIGATIONS

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

During the nine months ended September 30, 2013, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance as of December 31, 2012	$	118,023
Liabilities incurred	2,466
Liabilities settled	(542		)
Accretion expense (including discontinued operations of $944)	6,131
Reclassification associated with held for sale properties*	(19,474		)
Balance as of September 30, 2013	$	106,604

* Asset retirement obligation associated with Black Warrior Basin and North Louisiana/East Texas properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $25.8 million and $24.9 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of September 30, 2013 and December 31, 2012, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $2.2 million and $3.3 million as of September 30, 2013 and December 31, 2012, are

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included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

12. DISPOSITION OF PROPERTIES

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

13. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.

(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
Other comprehensive income (loss) before reclassifications	(10,924		)	4,157			(6,767		)
Amounts reclassified from accumulated other comprehensive income (loss)	(17,907		)	4,721			(13,186		)
Change in accumulated other comprehensive income (loss)	(28,831		)	8,878			(19,953		)
Balance as of September 30, 2013	$	15,365		$	(43,629	)	$	(28,264	)

The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).

	Three months ended			Nine months ended
	September 30, 2013			September 30, 2013
(in thousands)	Amounts Reclassified						Line Item Where Presented
Gains and (losses) on cash flow hedges:
Commodity contracts	$	8,433		$	30,226		Operating revenues
Interest rate swap	(446		)	(1,282		)	Interest expense
Total cash flow hedges	7,987			28,944
Income tax expense	(3,048		)	(11,037		)
Net of tax	4,939			17,907
Pension and postretirement plans:
Transition obligation	(74		)	(220		)	Operations and maintenance
Prior service cost	(78		)	(235		)	Operations and maintenance
Actuarial losses*	(2,036		)	(6,387		)	Operations and maintenance
Actuarial losses on settlement charges*	(46		)	(421		)	Regulatory asset
Total pension and postretirement plans	(2,234		)	(7,263		)
Income tax expense	783			2,542
Net of tax	(1,451		)	(4,721		)
Total reclassifications for the period	$	3,488		$	13,186

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

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14. RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 3, Derivative Commodity Instruments.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 13, Accumulated Other Comprehensive Income (Loss).

15. DISCONTINUED OPERATIONS

In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company will record a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013. The sale had an effective date of July 1, 2013 and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

During the third quarter of 2013, Energen Resources classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations and began marketing these assets. Energen Resources recognized a non-cash impairment writedown on these properties in the third quarter of 2013 of $24.6 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months and nine months ended September 30, 2013. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. This nonrecurring impairment writedown is classified as Level 3 fair value. The Company anticipates the sale being completed within the next twelve months and using the proceeds from the sale to repay short-term obligations. At December 31, 2012, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 20 Bcf of natural gas and 51 MBbl of oil.

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The following table details held-for-sale properties by major classes of assets and liabilities:

(in thousands)	September 30, 2013
	Black Warrior Basin			North Louisiana/East Texas			Total
Accounts receivable	$	3,704		$	1,418		$	5,122
Inventories	1,078			63			1,141
Oil and gas properties	304,012			348,380			652,392
Less accumulated depreciation, depletion and amortization	(183,011		)	(293,935		)	(476,946		)
Other property, net	1,970			183			2,153
Total assets held-for-sale	127,753			56,109			183,862
Accounts payable	(1,713		)	(2		)	(1,715		)
Royalty payable	(792		)	(936		)	(1,728		)
Other current liabilities	(358		)	(35		)	(393		)
Other long-term liabilities	(5,377		)	(14,732		)	(20,109		)
Total liabilities held-for-sale	(8,240		)	(15,705		)	(23,945		)
Total held-for-sale properties	$	119,513		$	40,404		$	159,917

During the first quarter of 2012, Energen Resources recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss from discontinued operations in the nine months ended September 30, 2012. The impairment was caused by the impact of lower future natural gas prices. This nonrecurring impairment writedown is classified as Level 3 fair value.

Gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. Accordingly, the results of operations for certain held-for-sale properties were reclassified and reported as discontinued operations for all prior periods presented. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.

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	Three months ended					Nine months ended
	September 30,					September 30,
(in thousands, except per share data)	2013			2012		2013			2012
Oil and gas revenues	$	18,258		$	18,895	$	55,483		$	57,601
Pretax income (loss) from discontinued operations	$	2,971		$	5,526	$	9,980		$	(6,028	)
Income tax expense (benefit)	1,105			1,975		3,711			(2,044		)
Income (Loss) From Discontinued Operations	$	1,866		$	3,551	$	6,269		$	(3,984	)
Loss on disposal of discontinued operations	$	(24,612	)	$	—	$	(24,612	)	$	—
Income tax benefit	(8,934		)	—		(8,934		)	—
Loss on Disposal of Discontinued Operations	$	(15,678	)	$	—	$	(15,678	)	$	—
Total Income (Loss) From Discontinued Operations	$	(13,812	)	$	3,551	$	(9,409	)	$	(3,984	)
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.05	)
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.05	)
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.06	)
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.06	)

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

RESULTS OF OPERATIONS

Energen had a net loss totaling $19.3 million ($0.27 per diluted share) for the three months ended September 30, 2013 compared with net income of $2.0 million ($0.03 per diluted share) for the same period in the prior year. In the third quarter of 2013, Energen’s loss from continuing operations totaled $5.5 million ($0.08 per diluted share) and compared with loss from continuing operations of $1.5 million ($0.02 per diluted share) in the same period a year ago. Loss from discontinued operations for the current-quarter period was $13.8 million as compared with income of $3.6 million from the prior-year third quarter. Energen Resources Corporation, Energen’s oil and gas subsidiary, had a net loss for the three months ended September 30, 2013, of $10.2 million as compared with a net gain of $12.4 million in the same quarter in the previous year. Energen Resources generated net income from continuing operations of $3.6 million in the current quarter as compared with $8.8 million in the same quarter last year. This decrease in net income from continuing operations was primarily the result of higher depreciation, depletion and amortization (DD&A) expense (approximately $24 million after-tax), increased lease operating expense excluding production taxes (approximately $7 million after-tax), higher administrative expense (approximately $7 million after-tax), increased production taxes (approximately $3 million after-tax), decreased natural gas liquids commodity prices (approximately $1 million after-tax), and a year-over-year after-tax $10 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $39.7 million non-cash mark-to-market loss on derivatives for the third quarter of 2013 and an after-tax $29.7 million non-cash mark-to-market loss on derivatives for the third quarter of 2012). Positively affecting net income was the impact of higher natural gas, oil and natural gas liquids production volumes (approximately $31 million after-tax) and increased natural gas and oil commodity prices (approximately $16 million after-tax). Energen’s natural gas utility, Alagasco, reported a net loss of $9.0 million in the third quarter of 2013 compared to net loss of $10.0 million in the same period last year.

For the 2013 year-to-date, Energen’s net income totaled $120.5 million ($1.67 per diluted share) compared to net income of $190.7 million ($2.64 per diluted share) for the same period in the prior year. For the nine months ended September 30, 2013, Energen’s income from continuing operations totaled $129.9 million ($1.80 per diluted share) and compared with income from continuing operations of $194.7 million ($2.69 per diluted share) in the same period a year ago. Discontinued operations generated a loss for the current year-to-date period of $9.4 million as compared with a loss of $4.0 million from the same period a year ago. Energen Resources generated net income for the nine months ended September 30, 2013, of $82.4 million as compared with income of $153.6 million in the previous period. Energen Resources generated net income from continuing operations of $91.7 million in the current year-to-date as compared with income of $157.4 million in the same period last year. Higher DD&A expense (approximately $55 million after-tax), increased lease operating expense excluding production taxes (approximately $33 million after-tax), higher administrative expense (approximately $16 million after-tax), increased production taxes (approximately $6 million after-tax), decreased natural gas liquids commodity prices (approximately $4 million after-tax), increased interest expense (approximately $2 million after-tax), lower natural gas production volumes (approximately $1 million after-tax) and a year-over-year after-tax $52.7 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $30.7 million non-cash mark-to-market loss on derivatives for the nine months ended September 30, 2013 and an after-tax $22 million non-cash mark-to-market gain on derivatives for the nine months ended September 30, 2012) were partially offset by increased oil and natural gas liquids production volumes (approximately $77 million after-tax) and higher natural gas and oil commodity prices (approximately $29 million after-tax). Alagasco’s net income of $37.6 million in the current year-to-date compared to net income of $37.2 million in the same period in the previous year.

Oil and Gas Operations

Revenues from continuing oil and gas operations rose 26.8 percent to $272.0 million for the three months ended September 30, 2013 largely as a result of higher production volumes and increased realized natural gas and oil commodity prices partially offset by the non-cash mark-to-market decrease in derivatives combined with decreased realized natural gas liquids commodity prices. Revenues from continuing oil and gas operations rose 9.5 percent to $875.4 million for the nine months ended September 30, 2013 primarily as a result of significantly increased oil and natural gas liquids production volumes along with increased realized natural gas and oil commodity prices partially offset by lower natural gas production volumes, decreased realized natural gas liquids commodity prices and the non-cash mark-to-market decrease in derivatives. During the current quarter, revenue per unit of production for natural gas increased 10.9 percent to $4.06 per thousand cubic feet (Mcf), while oil revenue per unit of production rose 8.3 percent to $89.67 per barrel. Natural gas liquids revenue per unit of production fell 3.8 percent to an average price of $0.75 per gallon. In the year-to-date, revenue per unit of production for natural gas rose 13.7 percent to $4.14 per Mcf, oil revenue per unit of production increased 3.7 percent to $87.59 per barrel and natural gas liquids revenue per unit of production fell 7.5 percent to an average price of $0.74 per gallon. Revenues per unit of production include realized prices and the effects of designated cash flow hedges and exclude the impact of the non-cash mark-to-market hedges.

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Production from continuing operations for the current quarter and year-to-date increased largely due to higher volumes related to increased field development in certain Permian Basin liquids-rich properties offset by normal production declines. Natural gas production in the third quarter rose 1.7 percent to 14.9 billion cubic feet (Bcf), oil volumes increased 21.5 percent to 2,764 thousand barrels (MBbl) and natural gas liquids production rose 45.6 percent to 36.7 million gallons (MMgal). For the year-to-date, natural gas production declined 1.5 percent to 43.4 Bcf, while oil volumes rose 19.6 percent to 7,670 MBbl. Natural gas liquids production increased 24.7 percent to 98.5 MMgal. Oil and natural gas liquids comprised approximately 59 percent and 58 percent of Energen Resources’ production from continuing operations for the current quarter and year-to-date, respectively.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company reflects gains and losses on the disposition of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations for those sales that qualify for such reporting under generally accepted accounting standards. During the three months and nine months ended September 30, 2013, Energen Resources recorded in loss on disposal of discontinued operations a non-cash impairment writedown of $24.6 million pre-tax on certain natural gas and oil assets located in North Louisiana/East Texas. Energen Resources had no disposal of discontinued operations during the third quarter of 2012 or the year-to-date ended September 30, 2012. The Company includes gains and losses on the disposition of assets that do not qualify as discontinued operations in operating revenues. Energen Resources recorded a pre-tax loss of $37,000 in the third quarter of 2013 and a pre-tax gain of $0.1 million in the year-to-date from the sale of various Permian Basin properties. Energen Resources recorded a pre-tax gain of $0.1 million in the third quarter of 2012 and a pre-tax gain of $0.2 million year-to-date from the sale of various properties.

Operations and maintenance (O&M) expense increased $21.2 million for the quarter and $77.1 million for the year-to-date. Lease operating expense (excluding production taxes) generally reflects year over year increases in the number of active wells resulting from Energen Resources’ ongoing development, exploratory and acquisition activities. Lease operating expense (excluding production taxes) increased $11.7 million for the quarter largely due to additional workover and repair expense (approximately $5.5 million), higher water disposal costs (approximately $1.9 million), increased gathering costs (approximately $1.6 million), increased marketing and transportation costs (approximately $1.5 million), higher electrical costs (approximately $0.9 million) and additional equipment rental expense (approximately $0.9 million) partially offset by lower ad valorem taxes (approximately $2 million). In the year-to-date, lease operating expense (excluding production taxes) increased $51.4 million primarily due to increased workover and repair expense (approximately $21.5 million), additional equipment rental expense (approximately $5.3 million), higher water disposal costs (approximately $5.3 million), increased gathering costs (approximately $3.8 million), higher marketing and transportation costs (approximately $2.9 million), increased ad valorem taxes (approximately $2.9 million), higher electrical costs (approximately $2.8 million), increased chemical and treatment costs (approximately $2.5 million) and increased environmental compliance costs (approximately $2.3 million). On a per unit basis, the average lease operating expense (excluding production taxes) for the current quarter was $11.30 per barrel of oil equivalent (BOE) as compared to $10.81 per BOE in the same period a year ago. For the nine months ended September 30, 2013, the average lease operating expense (excluding production taxes) was $12.20 per BOE as compared to $10.17 per BOE in the previous period. Administrative expense increased $11.2 million for the three months ended September 30, 2013 largely due to increased costs from the Company’s benefit and performance-based compensation plans (approximately $7.2 million), higher labor costs (approximately $2.2 million) and increased legal expenses (approximately $1.7 million). For the nine months ended September 30, 2013, administrative expense rose $25.2 million primarily due to increased costs from the Company’s benefit and performance-based compensation plans (approximately $15.1 million), higher labor costs (approximately $7.2 million) and increased legal expenses (approximately $2 million). Exploration expense decreased $1.7 million in the third quarter of 2013 and rose $0.5 million year-to-date.

Energen Resources’ DD&A expense for the quarter rose $39 million. For the year-to-date, Energen Resources’ DD&A expense increased $87.8 million. The average depletion rate for the current quarter was $20.27 per BOE as compared to $16.03 per BOE in the same period a year ago. For the nine months ended September 30, 2013, the average depletion rate was $19.10 per BOE as compared to $15.49 per BOE, excluding the asset impairment, in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $25.9 million and $62.2 million, respectively, to the increase in DD&A expense, was largely due to higher rates resulting from an increase in development costs and the impact from downward reserve revisions related to natural gas reserves at year-end. Higher production volumes contributed approximately $12.9 million and $25 million to the increase in DD&A expense for the quarter and year-to-date, respectively.

Energen Resources’ expense for taxes other than income taxes was $5.3 million and $9.5 million higher in the three months and nine months ended September 30, 2013, respectively, largely due to production-related taxes. In the quarter, higher natural gas and oil commodity market prices contributed approximately $3.4 million to the increase in production-related taxes and higher oil and natural gas liquids commodity production volumes contributed approximately $2 million to the increase. In the year-to-date, higher net commodity market prices contributed approximately $5.6 million to the increase in production-related taxes and higher commodity

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production volumes contributed approximately $4.1 million to the increase. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues decreased $13.4 million for the quarter largely due to adjustments from the utility’s rate setting mechanisms combined with a decrease in customer usage partially offset by a decrease in the pass-through of gas costs. During the third quarter of 2013, Alagasco had a net $4.3 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Additionally, during the three months and nine months ended September 30, 2013, Alagasco had a $10.9 million reduction in revenues related to the sale of its Metro Operations Center in August 2013. During the third quarter of 2012, Alagasco had a net $1.3 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the third quarter, weather was comparable with the same quarter in the prior year. Residential sales volumes rose slightly while commercial and industrial customer sales volumes rose 2.1 percent. Transportation volumes fell slightly in period comparisons. Revenues for the year-to-date rose $63.4 million primarily due to the pass-through of gas costs along with additional customer usage partially offset by adjustments from the utility’s rate setting mechanisms. During the year-to-date 2013, Alagasco had a net $10.6 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. In the 2012 year-to-date, Alagasco had a net reduction in revenues of $6.3 million pre-tax to bring the return on average common equity to midpoint within the allowed range of return. Weather, for the current year-to-date, that was 48.1 percent colder compared with the same period in the prior year contributed to a 32.6 percent increase in residential sales volumes and a 21.1 percent rise in commercial and industrial customer sales volumes. Transportation volumes decreased slightly in period comparisons. Decreased gas purchase volumes partially offset by higher gas costs resulted in a 2.3 percent decrease in cost of gas for the quarter. For the year-to-date a significant increase in gas costs combined with higher gas purchase volumes resulted in a 73.6 percent increase in cost of gas. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense declined 9.6 percent in the current quarter primarily due to lower distribution operation expenses (approximately $0.5 million) and decreased consulting and technology costs (approximately $0.5 million). In the nine months ended September 30, 2013, O&M expense increased slightly largely due to increased labor-related costs (approximately $3 million) and higher bad debt expense (approximately $0.8 million) partially offset by decreased consulting and technology expense (approximately $1 million) and lower insurance costs (approximately $0.8 million).

A 4.6 percent increase in depreciation expense in the current quarter and a 3.5 percent increase in the year-to-date was primarily due to the extension and replacement of the utility’s distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company rose $0.5 million in the third quarter of 2013 and $3.3 million year-to-date largely due to higher short-term borrowings. Other income for the Company increased $11.3 million for both the three months and nine months ended September 30, 2013 primarily due to the pre-tax gain of $10.9 million on the August 2013 sale of Alagasco’s Metro Operations Center. Income tax expense for the Company decreased $3.3 million and $36.6 million in the current quarter and year-to-date, respectively, largely due to lower pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $728.0 million as compared to $603.1 million in the prior period. The Company’s working capital needs were influenced by accrued taxes, commodity prices and the timing of payments and recoveries, including gas supply pass-through adjustments and refundable negative salvage costs.

The Company had a net outflow of cash from investing activities of $968.2 million for the nine months ended September 30, 2013 primarily due to additions of property, plant and equipment of $983 million. Energen Resources incurred on a cash basis $916 millionin capital expenditures primarily related to the acquisition and development of oil and gas properties. Utility capital expenditures on a cash basis totaled $67.1 million year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities and information systems.

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The Company provided net cash of $242.9 million from financing activities in the year-to-date primarily due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders and the issuance of common stock through the Company’s stock-based compensation plan.

Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2013, the Company expects its oil and gas capital spending to total approximately $1.1 billion, primarily all of which is for existing properties, including exploration to date of $321 million. On an annual basis, the development and exploration expenditures cannot be reasonably segregated as drilling and development throughout the course of the year may change the classification of locations currently identified as exploratory. 

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

Discontinued Operations

In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company will record a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013. The sale had an effective date of July 1, 2013 and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for sale and as discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

During the third quarter of 2013, Energen Resources classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and as discontinued operations and began marketing these assets. Energen Resources recognized a non-cash impairment writedown on these properties in the third quarter of 2013 of $24.6 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. This nonrecurring impairment writedown is classified as Level 3 fair value. The Company anticipates the sale being completed within the next twelve-months and using the proceeds from the sale to repay short-term obligations. At December 31, 2012, proved reserves associated with Energen’s North Louisiana/ East Texas properties totaled 20 Bcf of natural gas and 51 MBbl of oil.

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 nine months ended September 30, 2013. The impairment was caused by the impact of lower future natural gas prices. This nonrecurring impairment writedown is classified as Level 3 fair value.

Natural Gas Distribution

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current allowed range of return on average common equity is 13.15 percent to 13.65 percent through December 31, 2013. The Company’s current RSE order had an original term extending through December 31, 2014. At its meeting on November 5, 2013, the APSC voted to make certain RSE modifications effective January 1, 2014, which are described as follows. The term of the order is extended through September 30, 2018. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted will be 56.5 percent with Alagasco allowed to budget at the cap. Given existing economic conditions, Alagasco expects only modest growth in equity supporting Alagasco’s investment in its distribution system and support systems devoted to public service as annual dividends are typically paid by the utility.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010.

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Refunds of negative salvage costs to customers through lower tariff rates were $14.5 million, $14.2 million, $22.2 million and $2.7 million for the periods January through September 2013, January through December 2012, January through December 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $16.3 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $41 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a seven year period beginning January 1, 2013. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. The refunds as of September 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.

Alagasco is a mature utility operating in a slow-growth service area which includes municipalities that have in recent years experienced population declines. Alagasco’s average customer count for 2012 declined approximately 0.6 percent from 2011 and reflected a moderation in decline over the five-year trend. Other factors impacting Alagasco’s average customer count include recent warmer weather trends, enhanced credit and collection efforts and the loss of customers due to a 2011 weather event. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices, weather conditions and the underlying current and future economic conditions facing the utility’s customer base. During the nine months ended September 30, 2013, Alagasco reduced the bad debt reserve by approximately $0.4 million primarily due to certain aged receivables transitioned to the utility’s long-term collections, in addition to the impact of its collection related initiatives.

Alagasco maintains an investment in storage gas that is expected to average approximately $26 million in 2013 but will vary depending upon the price of natural gas. During 2013, Alagasco plans to invest an estimated $91 million in capital expenditures for the normal needs of its distribution and support systems and for technology-related projects designed to improve customer service. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities. Alagasco also may issue long-term debt periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.

In August 2013, Alagasco recorded a pre-tax gain of $10.9 million on the sale of its Metro Operations Center which is located in Birmingham, Alabama. The Company received approximately $13.8 million pre-tax in cash from the sale of this property. The gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. Based upon the November 5, 2013 review by the APSC, Alagasco will recognize the deferred revenues from the sale in the fourth quarter of 2013. Effective upon the sale of the Metro Operations Center, Alagasco leased the facility from the purchaser for a period of approximately 20 months.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps, collars and basis hedges typically with investment and commercial banks and energy-trading firms. At September 30, 2013, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at September 30, 2013. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010. 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 GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

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Energen Resources entered into the following transactions for the remainder of 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	3.0	Bcf	$4.82 Mcf	NYMEX Swaps
	8.9	Bcf	$4.51 Mcf	Basin Specific Swaps - San Juan
	1.6	Bcf	$3.64 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	6.0	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
Oil
2013	2,434	MBbl	$91.44 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	5,760	MBbl	$88.85 Bbl	NYMEX Swaps
Oil Basis Differential
2013	907	MBbl	$(2.99) Bbl	WTS/WTI Basis Swaps*
	1,070	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	12.0	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

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

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

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

	September 30, 2013
(in thousands)	Level 2*			Level 3*		Total
Current assets	$	(12,712	)	$	25,005	$	12,293
Noncurrent assets	6,828			5,958		12,786
Current liabilities	(40,970		)	9,042		(31,928		)
Noncurrent liabilities	(2,580		)	1,201		(1,379		)
Net derivative asset (liability)	$	(49,434	)	$	41,206	$	(8,228	)

	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

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

As of September 30, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which were classified as Level 2 fair values and included in the above table as current liabilities. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012.

Level 3 assets and liabilities as of September 30, 2013, represent an immaterial amount of total assets and liabilities. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $22 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $22 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets and requires the Commodities Futures Trading Commission (CFTC) and the Securities and Exchange Commission (SEC) to promulgate implementing rules and regulations. The Dodd-Frank Act imposes certain margin, clearing and trade execution requirements. Energen’s derivative transactions qualify for the end-user exception which exempts them from certain Dodd-Frank Act margin and exchange clearing requirements pursuant to final regulations adopted by the CFTC and SEC and published in the Federal Register on July 19, 2012. 

Credit Facilities and Working Capital

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

At September 30, 2013, the Company reported negative working capital of $1,008.7 million arising from current liabilities of $1,541.3 million exceeding current assets of $532.6 million. The negative working capital is primarily due to a $258 million increase in borrowings during the year-to-date 2013 and a $628 million increase in borrowings during 2012 under the syndicated unsecured credit facilities and in support of Energen’s capital projects. Generally Accepted Accounting Principles require classification as short term for obligations such as these that are subject to the execution of individual notes with maturity dates less than one year. The syndicated unsecured credit facilities were entered into on October 30, 2012 and have a five-year term. In addition, Energen Resources received $160 million (subject to closing adjustments) on the sale of its Black Warrior Basin coalbed methane properties in October 2013. Accordingly, the Company believes that it has adequate financing capacity available for its expected liquidity needs.

Working capital of Energen is also influenced by the fair value of the Company’s derivative financial instruments associated with future production. Energen’s accounts receivable and accounts payable at September 30, 2013 include $12.3 million and $31.9 million, respectively, associated with its derivative financial instruments. Working capital of Alagasco is additionally impacted by the recovery and pass-through of regulatory items and the seasonality of Alagasco’s business and reflects an expected pass-through to rate payers of $16.3 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates. Energen and Alagasco rely upon cash flows from operations supplemented by their syndicated unsecured credit facilities to fund working capital needs.

Credit Ratings

On April 26, 2013, Moody’s Investor Service updated its credit opinion for Energen and Alagasco confirming Energen’s senior unsecured credit rating as investment grade with a negative outlook. Alagasco’s senior unsecured credit rating was lowered one notch but remains investment grade with a negative outlook. Energen and Alagasco’s debt ratings by Standard & Poor’s are considered investment grade with a stable outlook.

Dividends

Energen expects to pay annual cash dividends of $0.58 per share on the Company’s common stock in 2013. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

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Contractual Cash Obligations

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. Except as discussed below, there have been no material changes to the contractual cash obligations of the Company since December 31, 2012.

Other Commitments

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

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004 forward. The Company preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004 forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2013.

On April 4, 2013, a New Mexico corporate tax bill was signed into law which gradually reduces the New Mexico state income tax rate from the current 7.6 percent to 5.9 percent over a five year period.  The Company recognized a $1.6 million income tax benefit during the second quarter of 2013, the period the law was enacted, to reflect the impact of this change.

Recent Accounting Standards Updates

See Note 14, Recently Issued Accounting Standards, in the Notes to Unaudited Condensed Financial Statements for information regarding recently issued accounting standards.

FORWARD LOOKING STATEMENTS AND RISK FACTORS

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

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties (many of which are beyond our control) that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, gas and natural gas liquids, fluctuations in the weather, drilling risks, costs associated with compliance with environmental and regulatory obligations, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, acts of nature, sabotage, terrorism (including cyber-attacks) and other similar acts that disrupt operations or cause damage greater than covered by insurance, future business decisions, utility customer growth and retention and usage per customer, litigation results and other factors and uncertainties discussed elsewhere in this report and in the Company’s other public filings and press releases, all of which are difficult to predict. While it is not possible to predict or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors which may affect the Company’s future business and financial performance.

Except as otherwise disclosed, the forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.

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

Market conditions or a downgrade in the credit ratings of the Company or its subsidiaries could negatively impact its cost of and ability to access capital for future development and working capital needs: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for lenders, the Company and its subsidiaries. In addition to operating results, business decisions relating to recapitalization, refinancing, restructuring, acquisition and disposition (including by sale, spin-off or distribution) transactions involving the Company, Energen Resources or Alagasco may negatively impact market and rating agency considerations regarding the credit of the Company or its subsidiaries, and the management of the Company periodically considers these types of transactions. Market volatility and credit market disruption may severely limit credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs, limit availability of funds to the Company and adversely affect the price of outstanding debt securities.

Energen Resources’ hedging activities may prevent Energen Resources from benefiting fully from price increases and expose Energen Resources to other risks, including counterparty credit risk: Although Energen Resources makes use of futures, swaps, options, collars and fixed-price contracts to mitigate price risk, fluctuations in future oil, gas and natural gas liquids prices could materially affect the Company’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options, collars and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position. In addition, various existing and pending financial reform rules and regulations could have an adverse effect on the ability of Energen Resources to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

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

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

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

38

due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

The Company’s operations involve operational risk including risk of personal injury, property damage and environmental damage and its insurance policies do not cover all such risks: Inherent in the oil and gas production activities of Energen Resources and the gas distribution activities of Alagasco are a variety of hazards and operation risks, such as:

• Pipeline and storage leaks, ruptures and spills;

• Equipment malfunctions and mechanical failures;

• Fires and explosions;

• Well blowouts, explosions and cratering; and

• Soil, surface water or groundwater contamination from petroleum constituents, hydraulic fracturing fluid, or produced water.

Such events could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial financial losses. The location of certain of our pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses and the insurance coverages are subject to retention levels and coverage limits. The occurrence of any of these events could adversely affect Energen Resources’, Alagasco’s and the Company’s financial positions, results of operations and cash flows.

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

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

The Company’s business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions:The Company relies on its information technology infrastructure to process, transmit and store electronic information critical for the efficient operation of its business and day-to-day operations. All information systems are potentially vulnerable to security threats, including hacking, viruses, other malicious software, and other unlawful attempts to disrupt or gain access to such systems. Breaches in the Company’s information technology infrastructure could lead to a material disruption in its business, including the theft, destruction, loss, misappropriation or release of confidential data or other business information, and may have a material adverse effect on the Company’s operations, financial position and results of operations.

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SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except sales price data)	2013			2012			2013			2012
Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$	62,073		$	49,422		$	196,311		$	156,308
Oil	183,950			147,710			607,975			578,167
Natural gas liquids	26,292			17,566			71,556			64,970
Other	(277)			(78)			(492		)	(106		)
Total	$	272,038		$	214,620		$	875,350		$	799,339
Non-cash mark-to-market gains (losses) included in operating revenues from continuing operations above
Natural gas	$	1,684		$	(4,159	)	$	16,610		$	(4,121	)
Oil	(63,889		)	(40,569		)	(63,861		)	36,355
Natural gas liquids	(1,355		)	(2,024		)	(1,208		)	1,801
Total	$	(63,560	)	$	(46,752	)	$	(48,459	)	$	34,035
Production volumes from continuing operations
Natural gas (MMcf)	14,868			14,622			43,428			44,076
Oil (MBbl)	2,764			2,275			7,670			6,414
Natural gas liquids (MMgal)	36.7			25.2			98.5			79.0
Production volumes from continuing operations (MBOE)	6,116			5,312			17,253			15,641
Total production volumes (MBOE)	6,758			6,026			19,159			17,850
Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments
Natural gas (Mcf)	$	4.06		$	3.66		$	4.14		$	3.64
Oil (barrel)	$	89.67		$	82.76		$	87.59		$	84.47
Natural gas liquids (gallon)	$	0.75		$	0.78		$	0.74		$	0.80
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.39		$	2.69		$	3.51		$	2.51
Oil (barrel)	$	103.22		$	86.55		$	92.69		$	89.92
Natural gas liquids (gallon)	$	0.68		$	0.68		$	0.65		$	0.78
Other data from continuing operations
Lease operating expense
Lease operating expense and other	$	69,086		$	57,397		$	210,455		$	159,052
Production taxes	18,939			13,531			49,598			39,882
Total	$	88,025		$	70,928		$	260,053		$	198,934
Depreciation, depletion and amortization	$	125,060		$	86,062		$	332,690		$	244,914
Capital expenditures	$	257,759		$	323,037		$	892,691		$	957,913
Exploration expense	$	8,949		$	10,644		$	13,902		$	13,382
Operating income	$	18,607		$	26,913		$	181,948		$	280,897

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Natural Gas Distribution
Operating revenues
Residential	$	31,201		$	30,658		$	259,492		$	201,537
Commercial and industrial	18,194			17,695			103,419			84,889
Transportation	13,197			13,505			45,261			42,765
Other	(14,224		)	(49		)	(17,605		)	(2,008		)
Total	$	48,368		$	61,809		$	390,567		$	327,183
Gas delivery volumes (MMcf)
Residential	1,384			1,378			15,379			11,601
Commercial and industrial	1,272			1,246			7,434			6,137
Transportation	11,237			11,252			34,733			34,835
Total	13,893			13,876			57,546			52,573
Other data
Depreciation and amortization	$	11,063		$	10,572		$	32,665		$	31,551
Capital expenditures	$	20,980		$	18,813		$	67,790		$	51,786
Operating income (loss)	$	(22,544	)	$	(12,743	)	$	58,968		$	70,265

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its gas supply exposure. Such instruments may include over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by the Company. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. All hedge transactions are subject to the Company’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. As of September 30, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015.

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

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

The Company’s interest rate exposure as of September 30, 2013, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at September 30, 2013 was 1.36 percent. The Company’s interest rate exposure on long-term debt as of September 30, 2013, was minimal since approximately 91 percent of long-term debt obligations were at fixed rates.

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ITEM 4. CONTROLS AND PROCEDURES

Energen Corporation

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

(b) During the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Alabama Gas Corporation

(a) Our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures were not effective at that reasonable assurance level due to the existence of a material weakness in our internal control over

financial reporting which is described below.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

Alabama Gas Corporation’s principal accounting officer failed to operate within the Company’s code of conduct and engaged in an override of internal controls during the second and third quarters of 2013. This officer requested that two vendors delay submission of invoices and bypassed controls for the timely accrual of liabilities and operating expenses for services rendered. Management has determined that the impact of this override resulted in an immaterial understatement of expenses for the quarter ended June 30, 2013 of approximately $76,000. Since the override was identified by management prior to preparation of financial statements for the quarter ended September 30, 2013, it did not result in misstatement for that quarter. However, an override of internal controls by a member of senior management could result in misstatements impacting all accounts and disclosures that would result in a material misstatement of the financial statements that would not be prevented or detected. Accordingly, our management has determined that this control deficiency constitutes a material weakness.

The principal accounting officer who overrode the control has separated from Alabama Gas Corporation and a successor has been elected by the Alabama Gas Corporation Board of Directors. The importance of timely invoicing has been reviewed with the Alabama Gas Corporation officers and with the two vendors involved.

(b) As described above in (a) there were changes in our internal control over financial reporting during the most recent fiscal quarter covered by this report.

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PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $1.8 million of which $1.6 million has been incurred and $0.2 million has been reserved.

In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the EPA’s investigation of a site which it refers to as the 35th Avenue Superfund Site located in Birmingham, Jefferson County, Alabama.  The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35th Avenue Superfund Site. In September 2013, Alagasco received from EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site.  The letter identifies Alagasco as a potentially responsible party (PRP) under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site.  The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination.  Alagasco has requested additional information from EPA regarding its designation as a PRP, and an opportunity to discuss this designation further with EPA. Alagasco is unable to determine the extent, if any, of its potential liability with respect to the proposed removal action and no amount has been accrued as of September 30, 2013.

Various other pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability. See Note 8, Commitments and Contingencies, in the Notes to Financial Statements for further discussion with respect to legal proceedings.

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

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs**
July 1, 2013 through July 31, 2013	29	*	$	53.32	—	8,992,700
August 1, 2013 through August 31, 2013	6,751	*	65.31		—	8,992,700
September 1, 2013 through September 30, 2013	5,418	*	73.96		—	8,992,700
Total	12,198		$	69.12	—	8,992,700

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

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

ITEM 6. EXHIBITS

31(a)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(b)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(c)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(d)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
32(a)	-	Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)	-	Section 906 Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350
101	-	The financial statements and notes thereto from Energen Corporation’s Quarterly Report on Form 10-Q for the
		quarter ended September 30, 2013 are formatted in XBRL

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		ENERGEN CORPORATION ALABAMA GAS CORPORATION
November 8, 2013	By	/s/ J. T. McManus, II
		J. T. McManus, II
		Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation
November 8, 2013	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
November 8, 2013	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
November 8, 2013	By	/s/ Leonarda M. DiChiara
		Leonarda M. DiChiara
		Vice President and Controller of Alabama Gas Corporation

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EX-31.A

Exhibit 31(a)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

November 8, 2013	By	/s/ J. T. McManus, II
		J. T. McManus, II Chairman, Chief Executive Officer and President of Energen Corporation

EX-31.B

Exhibit 31(b)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

November 8, 2013	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation

EX-31.C

Exhibit 31(c)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

November 8, 2013	By	/s/ J. T. McManus, II
		J. T. McManus, II Chairman and Chief Executive Officer of Alabama Gas Corporation

EX-31.D

Exhibit 31(d)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

November 8, 2013	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Alabama Gas Corporation

EX-32.A

Exhibit 32(a)

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Energen Corporation (the “Registrant”) on Form 10-Q for the period ended September 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of November 8, 2013

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

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

EX-32.B

Exhibit 32(b)

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Alabama Gas Corporation (the “Registrant”) on Form 10-Q for the period ended September 30, 2013, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of November 8, 2013

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

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

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Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	September 30, 2013				December 31, 2012
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension assets	$	263	$	69,249	$	170	$	90,708
Accretion and depreciation for asset retirement obligation	—		17,579		—		16,536
Risk management activities	—		—		2,593		—
Rate recovery of asset removal costs, net	—		2,176		—		3,322
Gas supply adjustment	10,925		—		42,726		—
Other	25		—		26		—
Total regulatory assets	$	11,213	$	89,004	$	45,515	$	110,566
Regulatory liabilities:
RSE adjustment	$	6,573	$	—	$	1,740	$	—
Unbilled service margin	6,351		—		25,078		—
Postretirement liabilities	—		13,951		—		1,237
Refundable negative salvage	16,321		40,946		18,265		53,467
Gain on sale of property	10,890		—		—		—
Asset retirement obligation	—		25,772		—		24,930
Other	33		745		33		770
Total regulatory liabilities	$	40,168	$	81,414	$	45,116	$	80,404

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

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

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Derivative Commodity Instruments

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Commodity Instruments

DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company recognizes all derivatives on the balance sheet and measures all derivatives at fair value. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at September 30, 2013. The largest counterparty net loss position at September 30, 2013, Morgan Stanley Capital Group, constituted approximately $19.8 million of Energen Resources’ total net loss on fair value of derivatives. At September 30, 2013, Energen Resources was in a net gain position with Macquarie Bank Limited for approximately $10.0 million.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in operating revenues immediately. All other derivative transactions not previously qualified for cash flow hedge accounting are still considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These derivatives are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur.  Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.

Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 will be accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.

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

(in thousands)	September 30, 2013
	Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	53,082			$	—	$	53,082
Long-term asset derivative instruments	18,346				—		18,346
Total derivative assets	71,428				—		71,428
Accounts receivable	(40,789		)	*	—		(40,789		)
Long-term asset derivative instruments	(5,560		)	*	—		(5,560		)
Accounts payable	(31,928		)		—		(31,928		)
Long-term liability derivative instruments	(1,379		)		—		(1,379		)
Total derivative liabilities	(79,656		)		—		(79,656		)
Total derivatives not designated	$	(8,228	)		$	—	$	(8,228	)

(in thousands)	December 31, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	87,514			$	—		$	87,514
Long-term asset derivative instruments	37,954				—			37,954
Total derivative assets	125,468				—			125,468
Accounts receivable	(37,326		)	*	—			(37,326		)
Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
Long-term liability derivative instruments	(8,726		)		—			(8,726		)
Total derivative liabilities	(52,862		)		—			(52,862		)
Total derivatives designated	72,606				—			72,606
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,604				—			14,604
Long-term asset derivative instruments	9,433				—			9,433
Total derivative assets	24,037				—			24,037
Accounts payable	—				(2,593		)	(2,593		)
Long-term liability derivative instruments	(874		)		—			(874		)
Total derivative liabilities	(874		)		(2,593		)	(3,467		)
Total derivatives not designated	23,163				(2,593		)	20,570
Total derivatives	$	95,769			$	(2,593	)	$	93,176

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

The Company had a net $10.3 million and a net $28.4 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of September 30, 2013, and December 31, 2012, respectively.

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

(in thousands)	Location on Statement of Income	Three months ended September 30, 2013			Three months ended September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of $42 and ($30,622)	—	$	69		$	(49,962	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	8,455		$	15,998
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(22	)	$	(3,042	)

(in thousands)	Location on Statement of Income	Nine months ended September 30, 2013			Nine months ended September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of ($6,669) and $30,621	—	$	(10,882	)	$	49,961
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	29,391		$	39,012
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	835		$	(1,372	)

The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:

(in thousands)	Location on Statement of Income	Three months ended September 30, 2013			Three months ended September 30, 2012
Loss recognized in income on derivatives	Operating revenues	$	(92,313	)	$	(45,618	)

(in thousands)	Location on Statement of Income	Nine months ended September 30, 2013			Nine months ended September 30, 2012
Gain (loss) recognized in income on derivatives	Operating revenues	$	(70,735	)	$	33,825

As of September 30, 2013, $13.1 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of September 30, 2013, the Company had 13.5 billion cubic feet (Bcf), 51.8 Bcf and 6.0 Bcf of natural gas hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 4.4 million barrels (MMBbl), 9.8 MMBbl and 5.8 MMBbl of oil and oil basis hedges which expire during 2013, 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 11.9 million gallons (MMgal) and 1.9 MMgal of natural gas liquid hedges which expire during 2013 and 2014, respectively, that are considered mark-to-market transactions. During 2013, the Company discontinued hedge accounting and reclassified gains of $6.7 million after-tax from other comprehensive income into operating revenues when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being held for sale.

Energen Resources entered into the following transactions for the remainder of 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	3.0	Bcf	$4.82 Mcf	NYMEX Swaps
	8.9	Bcf	$4.51 Mcf	Basin Specific Swaps - San Juan
	1.6	Bcf	$3.64 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	6.0	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
Oil
2013	2,434	MBbl	$91.44 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	5,760	MBbl	$88.85 Bbl	NYMEX Swaps
Oil Basis Differential
2013	907	MBbl	$(2.99) Bbl	WTS/WTI Basis Swaps*
	1,070	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	12.0	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

As of September 30, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010. 

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

	September 30, 2013
(in thousands)	Level 2*			Level 3*		Total
Current assets	$	(12,712	)	$	25,005	$	12,293
Noncurrent assets	6,828			5,958		12,786
Current liabilities	(40,970		)	9,042		(31,928		)
Noncurrent liabilities	(2,580		)	1,201		(1,379		)
Net derivative asset (liability)	$	(49,434	)	$	41,206	$	(8,228	)

	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 September 30, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which were classified as Level 2 fair values and included in the above table as current liabilities. Alagasco had no derivative instruments classified as Level 3 fair values as of December 31, 2012.

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $22 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $22 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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

	Three months ended			Three months ended
(in thousands)	September 30, 2013			September 30, 2012
Balance at beginning of period	$	51,131		$	103,456
Realized gains	10,852			18,737
Unrealized losses relating to instruments held at the reporting date*	(10,947		)	(46,983		)
Settlements during period	(9,830		)	(17,929		)
Balance at end of period	$	41,206		$	57,281

	Nine months ended			Nine months ended
(in thousands)	September 30, 2013			September 30, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	41,952			51,858
Unrealized losses relating to instruments held at the reporting date*	(48,835		)	(9,328		)
Settlements during period	(40,930		)	(51,050		)
Balance at end of period	$	41,206		$	57,281

*Includes $0.8 million and $4.7 million in mark-to-market gains for the three months and nine months ended September 30, 2013, respectively. Includes $7.9 million and $4.5 million in mark-to-market losses for the three months and nine months ended September 30, 2012, respectively.

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

(in thousands)	Fair Value as of September 30, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	9,499		Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf
2014	$	27,678		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
2015	$	1,201		Discounted Cash Flow	Forward Basis	($0.20) Mcf
Natural Gas Basis - Permian
2013	$	286		Discounted Cash Flow	Forward Basis	($0.14) Mcf
2014	$	825		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2013	$	(1,897	)	Discounted Cash Flow	Forward Basis	($1.06) Bbl
Oil Basis - WTI/WTI
2013	$	(641	)	Discounted Cash Flow	Forward Basis	($0.41 - $0.50) Bbl
Natural Gas Liquids
2013	$	4,255		Discounted Cash Flow	Forward Price	$0.74 - $0.81 Gal

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

The tables below set forth information about the offsetting of derivative assets and liabilities as follows:

	September 30, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	71,428	$	(46,349	)	$	25,079	$	—	$	—	$	25,079
Derivative liabilities	$	79,656	$	(46,349	)	$	33,307	$	—	$	—	$	33,307

	December 31, 2012
								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

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Derivative Commodity Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

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

(in thousands)	September 30, 2013
	Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	53,082			$	—	$	53,082
Long-term asset derivative instruments	18,346				—		18,346
Total derivative assets	71,428				—		71,428
Accounts receivable	(40,789		)	*	—		(40,789		)
Long-term asset derivative instruments	(5,560		)	*	—		(5,560		)
Accounts payable	(31,928		)		—		(31,928		)
Long-term liability derivative instruments	(1,379		)		—		(1,379		)
Total derivative liabilities	(79,656		)		—		(79,656		)
Total derivatives not designated	$	(8,228	)		$	—	$	(8,228	)

(in thousands)	December 31, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	87,514			$	—		$	87,514
Long-term asset derivative instruments	37,954				—			37,954
Total derivative assets	125,468				—			125,468
Accounts receivable	(37,326		)	*	—			(37,326		)
Long-term asset derivative instruments	(6,810		)	*	—			(6,810		)
Long-term liability derivative instruments	(8,726		)		—			(8,726		)
Total derivative liabilities	(52,862		)		—			(52,862		)
Total derivatives designated	72,606				—			72,606
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,604				—			14,604
Long-term asset derivative instruments	9,433				—			9,433
Total derivative assets	24,037				—			24,037
Accounts payable	—				(2,593		)	(2,593		)
Long-term liability derivative instruments	(874		)		—			(874		)
Total derivative liabilities	(874		)		(2,593		)	(3,467		)
Total derivatives not designated	23,163				(2,593		)	20,570
Total derivatives	$	95,769			$	(2,593	)	$	93,176

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

Schedule of Cash Flow Hedging Relationships on Financial Statements

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

(in thousands)	Location on Statement of Income	Three months ended September 30, 2013			Three months ended September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of $42 and ($30,622)	—	$	69		$	(49,962	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	8,455		$	15,998
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(22	)	$	(3,042	)

(in thousands)	Location on Statement of Income	Nine months ended September 30, 2013			Nine months ended September 30, 2012
Gain (loss) recognized in OCI on derivatives (effective portion), net of tax of ($6,669) and $30,621	—	$	(10,882	)	$	49,961
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	29,391		$	39,012
Gain (loss) recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	835		$	(1,372	)

Schedule of Derivatives Not Designated as Hedging Instruments on Income Statements

The following table details the effect of open and closed derivative commodity instruments not designated as hedging instruments on the income statement:

(in thousands)	Location on Statement of Income	Three months ended September 30, 2013			Three months ended September 30, 2012
Loss recognized in income on derivatives	Operating revenues	$	(92,313	)	$	(45,618	)

(in thousands)	Location on Statement of Income	Nine months ended September 30, 2013			Nine months ended September 30, 2012
Gain (loss) recognized in income on derivatives	Operating revenues	$	(70,735	)	$	33,825

Schedule of Hedging Transactions

Energen Resources entered into the following transactions for the remainder of 2013 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	3.0	Bcf	$4.82 Mcf	NYMEX Swaps
	8.9	Bcf	$4.51 Mcf	Basin Specific Swaps - San Juan
	1.6	Bcf	$3.64 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	31.4	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	6.0	Bcf	$4.07 Mcf	Basin Specific Swaps - San Juan
Oil
2013	2,434	MBbl	$91.44 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	5,760	MBbl	$88.85 Bbl	NYMEX Swaps
Oil Basis Differential
2013	907	MBbl	$(2.99) Bbl	WTS/WTI Basis Swaps*
	1,070	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	12.0	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
**WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

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

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

	September 30, 2013
(in thousands)	Level 2*			Level 3*		Total
Current assets	$	(12,712	)	$	25,005	$	12,293
Noncurrent assets	6,828			5,958		12,786
Current liabilities	(40,970		)	9,042		(31,928		)
Noncurrent liabilities	(2,580		)	1,201		(1,379		)
Net derivative asset (liability)	$	(49,434	)	$	41,206	$	(8,228	)

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

	Three months ended			Three months ended
(in thousands)	September 30, 2013			September 30, 2012
Balance at beginning of period	$	51,131		$	103,456
Realized gains	10,852			18,737
Unrealized losses relating to instruments held at the reporting date*	(10,947		)	(46,983		)
Settlements during period	(9,830		)	(17,929		)
Balance at end of period	$	41,206		$	57,281

	Nine months ended			Nine months ended
(in thousands)	September 30, 2013			September 30, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	41,952			51,858
Unrealized losses relating to instruments held at the reporting date*	(48,835		)	(9,328		)
Settlements during period	(40,930		)	(51,050		)
Balance at end of period	$	41,206		$	57,281

Schedule of Fair Value Inputs, Derivatives, Quantitative Information

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

(in thousands)	Fair Value as of September 30, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	9,499		Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf
2014	$	27,678		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
2015	$	1,201		Discounted Cash Flow	Forward Basis	($0.20) Mcf
Natural Gas Basis - Permian
2013	$	286		Discounted Cash Flow	Forward Basis	($0.14) Mcf
2014	$	825		Discounted Cash Flow	Forward Basis	($0.13 - $0.15) Mcf
Oil Basis - WTS/WTI
2013	$	(1,897	)	Discounted Cash Flow	Forward Basis	($1.06) Bbl
Oil Basis - WTI/WTI
2013	$	(641	)	Discounted Cash Flow	Forward Basis	($0.41 - $0.50) Bbl
Natural Gas Liquids
2013	$	4,255		Discounted Cash Flow	Forward Price	$0.74 - $0.81 Gal

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

Offsetting Assets and Liabilities

The tables below set forth information about the offsetting of derivative assets and liabilities as follows:

	September 30, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	71,428	$	(46,349	)	$	25,079	$	—	$	—	$	25,079
Derivative liabilities	$	79,656	$	(46,349	)	$	33,307	$	—	$	—	$	33,307

	December 31, 2012
								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

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

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

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

During the nine months ended September 30, 2013, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance as of December 31, 2012	$	118,023
Liabilities incurred	2,466
Liabilities settled	(542		)
Accretion expense (including discontinued operations of $944)	6,131
Reclassification associated with held for sale properties*	(19,474		)
Balance as of September 30, 2013	$	106,604

* Asset retirement obligation associated with Black Warrior Basin and North Louisiana/East Texas properties are included as liabilities related to assets held for sale in current liabilities on the balance sheet.

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $25.8 million and $24.9 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of September 30, 2013 and December 31, 2012, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $2.2 million and $3.3 million as of September 30, 2013 and December 31, 2012, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

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Commitments and Contingencies - Environmental Matters (Details) (Mitchell County, Texas, USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013 pit
Mitchell County, Texas
Environmental Exit Cost [Line Items]
Number of sites	9
Anticipated cost	$ 1.8
Costs incurred	1.6
Accrual for environmental loss contingencies	$ 0.2

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Discontinued Operations Balance Sheet and Income Statement (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Accounts receivable	$ 5,122		$ 5,122
Inventories	1,141		1,141
Oil and gas properties	652,392		652,392
Less accumulated depreciation, depletion and amortization	(476,946)		(476,946)
Other property, net	2,153		2,153
Total assets held-for-sale	183,862		183,862
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]
Accounts payable	(1,715)		(1,715)
Royalty payable	(1,728)		(1,728)
Other current liabilities	(393)		(393)
Other long-term liabilities	(20,109)		(20,109)
Total liabilities held-for-sale	(23,945)		(23,945)
Total held-for-sale properties	159,917		159,917
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Oil and gas revenues	18,258	18,895	55,483	57,601
Pretax income (loss) from discontinued operations	2,971	5,526	9,980	(6,028)
Income tax expense (benefit)	1,105	1,975	3,711	(2,044)
Income (Loss) From Discontinued Operations	1,866	3,551	6,269	(3,984)
Loss on disposal of discontinued operations	(24,612)	0	(24,612)	0
Income tax benefit	(8,934)	0	(8,934)	0
Loss on Disposal of Discontinued Operations	(15,678)	0	(15,678)	0
Total Income (Loss) From Discontinued Operations	(13,812)	3,551	(9,409)	(3,984)
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations (in dollars per share)	$ 0.03	$ 0.05	$ 0.09	$ (0.05)
Loss on Disposal of Discontinued Operations (in dollars per share)	$ (0.22)	$ 0.00	$ (0.22)	$ 0.00
Total Income (Loss) From Discontinued Operations (in dollars per share)	$ (0.19)	$ 0.05	$ (0.13)	$ (0.05)
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations (in dollars per share)	$ 0.03	$ 0.05	$ 0.09	$ (0.06)
Loss on Disposal of Discontinued Operations (in dollars per share)	$ (0.22)	$ 0.00	$ (0.22)	$ 0.00
Total Income (Loss) From Discontinued Operations (in dollars per share)	$ (0.19)	$ 0.05	$ (0.13)	$ (0.06)
Black Warrior Basin
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Accounts receivable	3,704		3,704
Inventories	1,078		1,078
Oil and gas properties	304,012		304,012
Less accumulated depreciation, depletion and amortization	(183,011)		(183,011)
Other property, net	1,970		1,970
Total assets held-for-sale	127,753		127,753
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]
Accounts payable	(1,713)		(1,713)
Royalty payable	(792)		(792)
Other current liabilities	(358)		(358)
Other long-term liabilities	(5,377)		(5,377)
Total liabilities held-for-sale	(8,240)		(8,240)
Total held-for-sale properties	119,513		119,513
North Louisiana/East Texas
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Accounts receivable	1,418		1,418
Inventories	63		63
Oil and gas properties	348,380		348,380
Less accumulated depreciation, depletion and amortization	(293,935)		(293,935)
Other property, net	183		183
Total assets held-for-sale	56,109		56,109
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]
Accounts payable	(2)		(2)
Royalty payable	(936)		(936)
Other current liabilities	(35)		(35)
Other long-term liabilities	(14,732)		(14,732)
Total liabilities held-for-sale	(15,705)		(15,705)
Total held-for-sale properties	$ 40,404		$ 40,404

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Derivative Commodity Instruments - Derivatives Measured at Fair Value on a Recurring Basis (Details) (USD $)							3 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Level 2 Fair Value, Measurements, Recurring		Dec. 31, 2012 Level 2 Fair Value, Measurements, Recurring		Sep. 30, 2013 Level 3	Sep. 30, 2013 Level 3 Fair Value, Measurements, Recurring		Dec. 31, 2012 Level 3 Fair Value, Measurements, Recurring		Sep. 30, 2013 Total Fair Value, Measurements, Recurring	Dec. 31, 2012 Total Fair Value, Measurements, Recurring	Sep. 30, 2013 Alabama Gas Corporation Fair Value, Measurements, Recurring	Dec. 31, 2012 Alabama Gas Corporation Level 2 Fair Value, Measurements, Recurring	Dec. 31, 2012 Alabama Gas Corporation Level 3 Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Current assets			$ (12,712,000)	[1]	$ (3,629,000)			$ 25,005,000	[1]	$ 68,421,000		$ 12,293,000	$ 64,792,000
Noncurrent assets	12,786,000	40,577,000	6,828,000	[1]	18,899,000			5,958,000	[1]	21,678,000		12,786,000	40,577,000
Current liabilities			(40,970,000)	[1]	(2,593,000)			9,042,000	[1]	0		(31,928,000)	(2,593,000)	0	(2,600,000)	0
Noncurrent liabilities	(1,961,000)	(11,305,000)	(2,580,000)		(8,520,000)			1,201,000		(1,080,000)		(1,379,000)	(9,600,000)
Net derivative asset (liability)			(49,434,000)	[1]	4,157,000	[1]		41,206,000	[1]	89,019,000	[1]	(8,228,000)	93,176,000
Impact on fair value of a 10 percent increase or decrease in commodity prices							22,000,000
Impact on results of operations of a 10 percent increase or decrease in commodity prices							$ 22,000,000

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

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2013

Pension Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	3,602		$	2,632		$	10,806		$	7,895
Interest cost	2,725			2,700			8,161			8,101
Expected long-term return on assets	(3,713		)	(3,563		)	(11,139		)	(10,689		)
Actuarial loss	3,597			2,099			10,962			6,297
Prior service cost amortization	123			129			367			388
Settlement charge	17			—			161			—
Net periodic expense	$	6,351		$	3,997		$	19,318		$	11,992

Postretirement Benefit Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	444		$	463		$	1,333		$	1,390
Interest cost	869			1,062			2,605			3,186
Expected long-term return on assets	(1,242		)	(1,109		)	(3,727		)	(3,328		)
Actuarial loss	—			9			—			27
Transition amortization	324			479			973			1,438
Net periodic expense	$	395		$	904		$	1,184		$	2,713

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Operating revenues from continuing operations
Oil and gas operations	$	272,038		$	214,620		$	875,350		$	799,339
Natural gas distribution	48,368			61,809			390,567			327,183
Total	$	320,406		$	276,429		$	1,265,917		$	1,126,522
Operating income (loss) from continuing operations
Oil and gas operations	$	18,607		$	26,913		$	181,948		$	280,897
Natural gas distribution	(22,544		)	(12,743		)	58,968			70,265
Eliminations and corporate expenses	(115		)	(206		)	(345		)	(857		)
Total	$	(4,052	)	$	13,964		$	240,571		$	350,305
Other income (expense)
Oil and gas operations	$	(13,209	)	$	(12,703	)	$	(38,686	)	$	(35,402	)
Natural gas distribution	7,973			(3,274		)	1,477			(10,062		)
Eliminations and other	175			186			405			390
Total	$	(5,061	)	$	(15,791	)	$	(36,804	)	$	(45,074	)
Income (loss) from continuing operations before income taxes	$	(9,113	)	$	(1,827	)	$	203,767		$	305,231

(in thousands)	September 30, 2013		December 31, 2012
Identifiable assets
Oil and gas operations	$	5,444,672	$	4,975,170
Natural gas distribution	1,127,487		1,177,134
Eliminations and other	42,713		23,586
Total	$	6,614,872	$	6,175,890

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Employee Benefit Plans (Details) (USD $)	3 Months Ended		1 Months Ended	3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended
	Sep. 30, 2013 pension_plan	Mar. 31, 2013	Jan. 31, 2013 Pension Plans	Sep. 30, 2013 Pension Plans	Sep. 30, 2012 Pension Plans	Sep. 30, 2013 Pension Plans	Sep. 30, 2012 Pension Plans	Sep. 30, 2013 Postretirement Benefit Plans	Sep. 30, 2012 Postretirement Benefit Plans	Sep. 30, 2013 Postretirement Benefit Plans	Sep. 30, 2012 Postretirement Benefit Plans	Sep. 30, 2013 Alabama Gas Corporation
Defined Benefit Plan Disclosure
Number of defined benefit non-contributory pension plans and certain nonqualified supplemental pension plans	2
Components of net periodic benefit cost:
Service cost				$ 3,602,000	$ 2,632,000	$ 10,806,000	$ 7,895,000	$ 444,000	$ 463,000	$ 1,333,000	$ 1,390,000
Interest cost				2,725,000	2,700,000	8,161,000	8,101,000	869,000	1,062,000	2,605,000	3,186,000
Expected long-term return on assets				(3,713,000)	(3,563,000)	(11,139,000)	(10,689,000)	(1,242,000)	(1,109,000)	(3,727,000)	(3,328,000)
Actuarial loss				3,597,000	2,099,000	10,962,000	6,297,000	0	9,000	0	27,000
Prior service cost amortization				123,000	129,000	367,000	388,000
Settlement charge				17,000	0	161,000	0
Transition amortization								324,000	479,000	973,000	1,438,000
Net periodic expense				6,351,000	3,997,000	19,318,000	11,992,000	395,000	904,000	1,184,000	2,713,000
Estimated required future employer contributions in current fiscal year				0		0
Contributions by employer in current fiscal year			9,000,000					400,000		1,200,000
Benefit payments made in current fiscal year				200,000		1,100,000
Estimated future benefit payments in current fiscal year						0
Settlement charges	64,000	500,000
Settlement charges expensed	100,000
Settlements recognized as a pension asset												400,000
Estimated future employer contributions in current fiscal year										400,000
Settlement charge expensed	18,000
Recognized as regulatory asset												$ 46,000

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Regulatory Matters (Details) (Alabama Gas Corporation, USD $)	0 Months Ended		1 Months Ended	3 Months Ended		9 Months Ended					3 Months Ended			0 Months Ended
	Dec. 01, 2012	Dec. 01, 2011	Aug. 31, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 APSC Approved Expension of ESR, November 1, 2010	Sep. 30, 2013 Force Majeure Event Costs APSC Approved Expension of ESR, November 1, 2010	Sep. 30, 2013 Force Majeure Events Costs APSC Approved Expension of ESR, November 1, 2010	Sep. 30, 2013 Environmental Response and Self Insurance Costs APSC Approved Expension of ESR, November 1, 2010	Sep. 30, 2013 Minimum	Sep. 30, 2013 Maximum	Nov. 05, 2013 Subsequent Event	Nov. 05, 2013 Subsequent Event APSC	Nov. 05, 2013 Subsequent Event APSC Minimum	Nov. 05, 2013 Subsequent Event APSC Maximum
Regulatory Matters [Line Items]
Approved return on equity																10.50%	10.95%
Adjusting point															10.80%
Performance based adjustment on adjusting point														0.05%
Equity upon which a return will be permitted														56.50%
Approved increase														1.75%
Allowed return on average common equity												13.15%	13.65%
Rate increases as percentage of prior year revenues													4.00%
Revenue reductions (increase) of rate adjustments	$ (7,800,000)	$ (13,000,000)	$ 10,900,000	$ 4,300,000	$ 1,300,000	$ 10,600,000	$ 6,300,000
Limitation on return on equity as percentage of total capitalization													55.00%
Return on Equity adjustment requirements description						RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range.
Adjustment requirement threshold for return on equity as percentage of operations and maintenance expenses to Consumer Price Index				0.75
Extraordinary operating and maintenance expenses minimum amount charged to Enhanced Stability Reserve									275,000	412,500	1,000,000
Large commercial and industrial customer budget minimum amount charged to Enhanced Stability Reserve								350,000
Enhanced Stability Reserve refund period				9 years
Enhanced Stability Reserve amortization period				5 years
Enhanced Stability Reserve, amortization expense						$ 660,000

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Derivative Commodity Instruments - Quantitative Disclosures About Fair Value (Details) (USD $) In Thousands, unless otherwise specified				9 Months Ended			9 Months Ended					9 Months Ended				9 Months Ended			9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2013	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2013 Minimum	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2013 Maximum	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2014	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2014 Minimum	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2014 Maximum	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2015	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - Permian 2013	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - Permian 2014	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - Permian 2014 Minimum	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - Permian 2014 Maximum	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Oil Basis - WTS/WTI 2013	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Oil Basis - WTI/WTI 2013	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Oil Basis - WTI/WTI 2013 Minimum	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Oil Basis - WTI/WTI 2013 Maximum	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Liquids 2013	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Liquids 2013 Minimum	Sep. 30, 2013 Income Approach Valuation Technique Level 3 Natural Gas Liquids 2013 Maximum
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of September 30, 2013	$ 25,079	$ 105,369	$ 9,499			$ 27,678			$ 1,201	$ 286	$ 825							$ 4,255
Fair Value as of September 30, 2013	$ 33,307	$ 12,193												$ (1,897)	$ (641)
Fair Value Inputs, Price Per Cubic Foot				0.12	0.14		0.13	0.15	0.20	0.14		0.13	0.15
Fair Value Inputs, Price Per Barrel														1.06		0.41	0.50
Fair Value Inputs, Price Per Gallon																			0.74	0.81

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

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Accumulated Other Comprehensive Income (Loss) (Tables)

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.

(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
Other comprehensive income (loss) before reclassifications	(10,924		)	4,157			(6,767		)
Amounts reclassified from accumulated other comprehensive income (loss)	(17,907		)	4,721			(13,186		)
Change in accumulated other comprehensive income (loss)	(28,831		)	8,878			(19,953		)
Balance as of September 30, 2013	$	15,365		$	(43,629	)	$	(28,264	)

Reclassification out of Accumulated Other Comprehensive Income

The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).

	Three months ended			Nine months ended
	September 30, 2013			September 30, 2013
(in thousands)	Amounts Reclassified						Line Item Where Presented
Gains and (losses) on cash flow hedges:
Commodity contracts	$	8,433		$	30,226		Operating revenues
Interest rate swap	(446		)	(1,282		)	Interest expense
Total cash flow hedges	7,987			28,944
Income tax expense	(3,048		)	(11,037		)
Net of tax	4,939			17,907
Pension and postretirement plans:
Transition obligation	(74		)	(220		)	Operations and maintenance
Prior service cost	(78		)	(235		)	Operations and maintenance
Actuarial losses*	(2,036		)	(6,387		)	Operations and maintenance
Actuarial losses on settlement charges*	(46		)	(421		)	Regulatory asset
Total pension and postretirement plans	(2,234		)	(7,263		)
Income tax expense	783			2,542
Net of tax	(1,451		)	(4,721		)
Total reclassifications for the period	$	3,488		$	13,186

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

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

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Reconciliation of Earnings Per Share (EPS) Reconciliation of Earnings Per Share (EPS) (Tables)

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation

	Three months ended							Three months ended
(in thousands, except per share amounts)	September 30, 2013							September 30, 2012
	Net				Per Share			Net			Per Share
	Loss			Shares	Amount			Income		Shares	Amount
Basic EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,130	$	0.03
Effect of dilutive securities
Stock options				—						183
Non-vested restricted stock				—						3
Diluted EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,316	$	0.03

In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 242,560 of excluded shares for the three months ended September 30, 2013.

	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2013					September 30, 2012
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	120,461	72,220	$	1.67	$	190,739	72,121	$	2.64
Effect of dilutive securities
Stock options			41					177
Non-vested restricted stock			10					3
Performance share awards			1					—
Diluted EPS	$	120,461	72,272	$	1.67	$	190,739	72,301	$	2.64

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Consolidated Condensed Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current Assets
Allowance for doubtful accounts	$ 5,296	$ 6,549
Shareholders’ Equity
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	75,485,159	75,067,760
Treasury stock, shares	2,977,920	2,998,620
Alabama Gas Corporation
Current Assets
Allowance for doubtful accounts	$ 5,300	$ 5,700
Shareholders’ Equity
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	120,000	120,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	3,000,000	3,000,000
Common stock, shares issued	1,972,052	1,972,052

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Basis of Presentation

9 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

BASIS OF PRESENTATION

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2012, 2011 and 2010, included in the 2012 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

On December 31, 2012, the Company and Alagasco revised the presentation of outstanding checks in its financial statements to reflect outstanding checks as a reduction in cash as of the date the checks were released for payment. The effect of not revising the presentation of cash balances for the nine months ended September 30, 2012 resulted in an increase of $1.9 million and a decrease of $0.8 million to Energen and Alagasco’s operating cash flows, respectively. The Company and Alagasco determined that the amounts were not material to the respective statements of cash flows. This adjustment had no impact on Energen or Alagasco’s statements of income.

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Reconciliation of Earnings Per Share (EPS)

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Reconciliation of Earnings Per Share (EPS)

RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended							Three months ended
(in thousands, except per share amounts)	September 30, 2013							September 30, 2012
	Net				Per Share			Net			Per Share
	Loss			Shares	Amount			Income		Shares	Amount
Basic EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,130	$	0.03
Effect of dilutive securities
Stock options				—						183
Non-vested restricted stock				—						3
Diluted EPS	$	(19,298	)	72,346	$	(0.27	)	$	2,046	72,316	$	0.03

In periods of loss, shares that otherwise would have been included in diluted average common shares outstanding are excluded. The Company had 242,560 of excluded shares for the three months ended September 30, 2013.

	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2013					September 30, 2012
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	120,461	72,220	$	1.67	$	190,739	72,121	$	2.64
Effect of dilutive securities
Stock options			41					177
Non-vested restricted stock			10					3
Performance share awards			1					—
Diluted EPS	$	120,461	72,272	$	1.67	$	190,739	72,301	$	2.64

The Company had the following shares that were excluded from the computation of diluted EPS, as their effect was non-dilutive:

	Three months ended September 30,		Nine months ended September 30,
(in thousands)	2013	2012	2013	2012
Stock options	—	850	875	850
Performance share awards	—	—	79	—

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Regulatory Matters

9 Months Ended

Sep. 30, 2013

Regulated Operations [Abstract]

Regulatory Matters

REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. The Company’s current RSE order had an original term extending through December 31, 2014. At its meeting on November 5, 2013, the APSC voted to make certain RSE modifications effective January 1, 2014, which are described as follows. The term of the order is extended through September 30, 2018. Alagasco’s allowed range of return on average common equity will be 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. Alagasco is eligible to receive a performance based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted will be 56.5 percent with Alagasco allowed to budget at the cap. The inflation-based Cost Control Mechanism (CCM) will be adjusted to allow annual increases to operations and maintenance (O&M) expense using the June Consumer Price Index For All Urban Consumers (Index Range) each rate year plus or minus 1.75 percent and from a 2007 base year, adjusted for inflation using the Index Range.  Alagasco expects these modifications to be included in a final written order in the fourth quarter of 2013.

Alagasco’s current allowed range of return on average common equity is 13.15 percent to 13.65 percent through December 31, 2013. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and nine months ended September 30, 2013, Alagasco had a net $4.3 million pre-tax and a net $10.6 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Additionally, during the three months and nine months ended September 30, 2013, Alagasco had a $10.9 million reduction in revenues related to the sale of its Metro Operations Center in August 2013. During the three months and nine months ended September 30, 2012, Alagasco had a net $1.3 million and a net $6.3 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $7.8 million and a $13.0 million annual increase in revenues became effective December 1, 2012 and 2011, respectively.

RSE currently limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Currently, under the inflation-based CCM established by the APSC, if the percentage change in O&M expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the September Index Range on a rate year basis, no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2013 and 2012.

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

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

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

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

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Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Allowance for Credit Losses on Financing Receivables

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

(in thousands)
Allowance for credit losses as of December 31, 2012	$	470
Provision	191
Allowance for credit losses as of September 30, 2013	$	661

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures

The following table details held-for-sale properties by major classes of assets and liabilities:

(in thousands)	September 30, 2013
	Black Warrior Basin			North Louisiana/East Texas			Total
Accounts receivable	$	3,704		$	1,418		$	5,122
Inventories	1,078			63			1,141
Oil and gas properties	304,012			348,380			652,392
Less accumulated depreciation, depletion and amortization	(183,011		)	(293,935		)	(476,946		)
Other property, net	1,970			183			2,153
Total assets held-for-sale	127,753			56,109			183,862
Accounts payable	(1,713		)	(2		)	(1,715		)
Royalty payable	(792		)	(936		)	(1,728		)
Other current liabilities	(358		)	(35		)	(393		)
Other long-term liabilities	(5,377		)	(14,732		)	(20,109		)
Total liabilities held-for-sale	(8,240		)	(15,705		)	(23,945		)
Total held-for-sale properties	$	119,513		$	40,404		$	159,917

	Three months ended					Nine months ended
	September 30,					September 30,
(in thousands, except per share data)	2013			2012		2013			2012
Oil and gas revenues	$	18,258		$	18,895	$	55,483		$	57,601
Pretax income (loss) from discontinued operations	$	2,971		$	5,526	$	9,980		$	(6,028	)
Income tax expense (benefit)	1,105			1,975		3,711			(2,044		)
Income (Loss) From Discontinued Operations	$	1,866		$	3,551	$	6,269		$	(3,984	)
Loss on disposal of discontinued operations	$	(24,612	)	$	—	$	(24,612	)	$	—
Income tax benefit	(8,934		)	—		(8,934		)	—
Loss on Disposal of Discontinued Operations	$	(15,678	)	$	—	$	(15,678	)	$	—
Total Income (Loss) From Discontinued Operations	$	(13,812	)	$	3,551	$	(9,409	)	$	(3,984	)
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.05	)
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.05	)
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.06	)
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.06	)

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Derivative Commodity Instruments - Hedging Transactions (Details) (Cash Flow Hedging)	9 Months Ended
	Sep. 30, 2013 Mcf
Natural Gas | 2013 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	3,000,000
Average Contract Price, per Mcf	4.82
Natural Gas | 2013 | Basin Specific Swaps - San Juan
Derivative [Line Items]
Total Hedged Volumes	8,900,000
Average Contract Price, per Mcf	4.51
Natural Gas | 2013 | Basin Specific Swaps - Permian
Derivative [Line Items]
Total Hedged Volumes	1,600,000
Average Contract Price, per Mcf	3.64
Natural Gas | 2014 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	10,600,000
Average Contract Price, per Mcf	4.55
Natural Gas | 2014 | Basin Specific Swaps - San Juan
Derivative [Line Items]
Total Hedged Volumes	31,400,000
Average Contract Price, per Mcf	4.60
Natural Gas | 2014 | Basin Specific Swaps - Permian
Derivative [Line Items]
Total Hedged Volumes	9,700,000
Average Contract Price, per Mcf	3.81
Natural Gas | 2015 | Basin Specific Swaps - San Juan
Derivative [Line Items]
Total Hedged Volumes	6,000,000
Average Contract Price, per Mcf	4.07
Crude Oil | 2013 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	2,434,000
Average Contract Price, per Bbl	91.44
Crude Oil | 2013 | WTS/WTI Basis Swaps
Derivative [Line Items]
Total Hedged Volumes	907,000	[1]
Average Contract Price, per Bbl	(2.99)	[1]
Crude Oil | 2013 | WTI/WTI Basis Swaps
Derivative [Line Items]
Total Hedged Volumes	1,070,000	[2]
Average Contract Price, per Bbl	(1.00)	[2]
Crude Oil | 2014 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	9,796,000
Average Contract Price, per Bbl	92.64
Crude Oil | 2015 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	5,760,000
Average Contract Price, per Bbl	88.85
Natural Gas Liquids | 2013 | Liquids Swaps
Derivative [Line Items]
Total Hedged Volumes	12,000,000
Average Contract Price, per Bbl	1.02

[1] WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

[2] WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

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

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

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Financial Instruments (Details) (USD $)	3 Months Ended	9 Months Ended					9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2011 Swap Senior Loans	Sep. 30, 2013 Swap Senior Loans Level 1	Dec. 31, 2012 Swap Senior Loans Level 1	Dec. 31, 2011 Senior Term Loans, Due March 31, 2014 to November 29, 2016 Swap Senior Loans	Sep. 30, 2013 Alabama Gas Corporation	Dec. 31, 2012 Alabama Gas Corporation	Sep. 30, 2013 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Dec. 31, 2012 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Sep. 30, 2013 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure Alabama Gas Corporation	Dec. 31, 2012 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure Alabama Gas Corporation	Sep. 30, 2013 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Sep. 30, 2013 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure Alabama Gas Corporation
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt fair value									$ 1,188,200,000	$ 1,255,800,000	$ 262,800,000	$ 284,700,000	$ 1,154,000,000	$ 250,000,000
Face amount						200,000,000
Interest rate			2.4175%
Interest rate cash flow hedge liability at fair value				2,100,000	3,300,000
Financing receivable							10,800,000	10,700,000
Financing receivable recorded investment average balance 0 to 60 days past due							3,000
Average finance receivable term							84 months
Time after which delinquent accounts are evaluated	90 days
Financing receivable recorded investment, equal to greater than 90 days past due							700,000	500,000
Financing Receivable, Allowance for Credit Losses [Roll Forward]
Allowance for credit losses as of December 31, 2012		470,000
Provision		191,000
Allowance for credit losses as of September 30, 2013	$ 661,000	$ 661,000

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Stock Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	9 Months Ended	1 Months Ended	3 Months Ended						9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2013 Stock options	Sep. 30, 2013 Stock options	Jan. 31, 2013 Restricted Stock	Sep. 30, 2013 Restricted Stock	Sep. 30, 2013 Performance share awards 2 year vesting period	Sep. 30, 2013 Performance share awards 3 year vesting period	Sep. 30, 2013 Performance share awards Petrotech Incentive Plan 3 year vesting period	Sep. 30, 2013 Stock Appreciation Rights (SARs)	Mar. 31, 2013 Restricted Stock Units (RSUs) Petrotech Incentive Plan	Sep. 30, 2013 Restricted Stock Units (RSUs) Petrotech Incentive Plan	Sep. 30, 2013 Restricted Stock Units (RSUs) Petrotech Incentive Plan 3 year vesting period	Sep. 30, 2013 Restricted Stock Units (RSUs) Petrotech Incentive Plan 3 year vesting period	Sep. 30, 2013 Restricted Stock Units (RSUs) Petrotech Incentive Plan 17 month vesting period	Sep. 30, 2013 Restricted Stock Units (RSUs) Petrotech Incentive Plan 17 month vesting period	Sep. 30, 2013 Deferred Compensation	Sep. 30, 2013 Deferred Compensation
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period		3 years		3 years	2 years	3 years	3 years	3 years				3 years		17 months
Expiration period	10 years
Grants in period, options		134,076
Grants in period, options, fair value		$ 16.66
Grants in period (in shares)			46,121		84,311	80,395	52,768	88,000	33,796		5,854		2,952
Grants in period, fair value (in dollars per share)			$ 48.36		$ 59.19	$ 60.81	$ 133.58	$ 39.10		$ 75.67				$ 75.88
Noncash payments for repurchase of common stock															$ 0.8	$ 0.9

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

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2013

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

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	3,602		$	2,632		$	10,806		$	7,895
Interest cost	2,725			2,700			8,161			8,101
Expected long-term return on assets	(3,713		)	(3,563		)	(11,139		)	(10,689		)
Actuarial loss	3,597			2,099			10,962			6,297
Prior service cost amortization	123			129			367			388
Settlement charge	17			—			161			—
Net periodic expense	$	6,351		$	3,997		$	19,318		$	11,992

There are no required contributions to the qualified pension plans during 2013. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $9.0 million to the qualified pension plans in January 2013. No additional discretionary contributions are expected to be made to the pension plans during 2013. During 2014, the Company may make discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. For the three months and nine months ending September 30, 2013, the Company made benefit payments aggregating $0.2 million and $1.1 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $36,000 through the remainder of 2013. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension and postretirement asset in regulatory assets at Alagasco. In the third quarter of 2013, the Company incurred a settlement charge of $64,000 for the payment of lump sums from the nonqualified supplemental retirement plans, of which $18,000 was expensed and $46,000 was recognized as a pension and postretirement asset in regulatory assets at Alagasco.

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	444		$	463		$	1,333		$	1,390
Interest cost	869			1,062			2,605			3,186
Expected long-term return on assets	(1,242		)	(1,109		)	(3,727		)	(3,328		)
Actuarial loss	—			9			—			27
Transition amortization	324			479			973			1,438
Net periodic expense	$	395		$	904		$	1,184		$	2,713

For the three months and nine months ended September 30, 2013, the Company made contributions aggregating $0.4 million and $1.2 million to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $0.4 million to the postretirement benefit plans through the remainder of 2013.

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

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Consolidated Condensed Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating Revenues
Oil and gas operations	$ 272,038	$ 214,620	$ 875,350	$ 799,339
Natural gas distribution	48,368	61,809	390,567	327,183
Total operating revenues	320,406	276,429	1,265,917	1,126,522
Operating Expenses
Cost of gas	20,435	20,924	163,448	94,179
Operations and maintenance	141,271	123,730	413,401	336,568
Depreciation, depletion and amortization	136,123	96,634	365,355	276,465
Income taxes
Deferred			51,682	80,724
Taxes, other than income taxes	24,858	19,572	77,955	64,314
Accretion expense	1,771	1,605	5,187	4,691
Total operating expenses	324,458	262,465	1,025,346	776,217
Operating Income (Loss)	(4,052)	13,964	240,571	350,305
Other Income (Expense)
Interest expense	(17,689)	(17,195)	(51,751)	(48,447)
Other income	13,062	1,488	15,578	3,678
Other expense	(434)	(84)	(631)	(305)
Total other expense	(5,061)	(15,791)	(36,804)	(45,074)
Interest Expense
Income (Loss) From Continuing Operations Before Income Taxes	(9,113)	(1,827)	203,767	305,231
Income tax expense (benefit)	(3,627)	(322)	73,897	110,508
Income (Loss) From Continuing Operations	(5,486)	(1,505)	129,870	194,723
Discontinued Operations, net of taxes
Income (loss) from discontinued operations	1,866	3,551	6,269	(3,984)
Loss on disposal of discontinued operations	(15,678)	0	(15,678)	0
Total Income (Loss) From Discontinued Operations	(13,812)	3,551	(9,409)	(3,984)
Net Income (Loss)	(19,298)	2,046	120,461	190,739
Diluted Earnings Per Average Common Share
Continuing Operations (in dollars per share)	$ (0.08)	$ (0.02)	$ 1.80	$ 2.69
Discontinued operations (in dollars per share)	$ (0.19)	$ 0.05	$ (0.13)	$ (0.05)
Diluted Earnings Per Average Common Share (in dollars per share)	$ (0.27)	$ 0.03	$ 1.67	$ 2.64
Basic Earnings Per Average Common Share
Continuing Operations (in dollars per share)	$ (0.08)	$ (0.02)	$ 1.80	$ 2.70
Discontinued operations (in dollars per share)	$ (0.19)	$ 0.05	$ (0.13)	$ (0.06)
Net Income (Loss) (in dollars per share)	$ (0.27)	$ 0.03	$ 1.67	$ 2.64
Dividends Per Common Share (in dollars per share)	$ 0.145	$ 0.14	$ 0.435	$ 0.420
Diluted Average Common Shares Outstanding	72,346	72,316	72,272	72,301
Basic Average Common Shares Outstanding	72,346	72,130	72,220	72,121
Alabama Gas Corporation
Operating Revenues
Natural gas distribution	48,368	61,809	390,567	327,183
Operating Expenses
Cost of gas	20,435	20,924	163,448	94,179
Operations and maintenance	33,650	37,235	107,672	107,470
Depreciation, depletion and amortization	11,063	10,572	32,665	31,551
Income taxes
Current	(7,703)	(9,242)	16,440	13,567
Deferred	2,093	3,264	6,448	9,431
Taxes, other than income taxes	5,764	5,821	27,814	23,718
Total operating expenses	65,302	68,574	354,487	279,916
Operating Income (Loss)	(16,934)	(6,765)	36,080	47,267
Other Income (Expense)
Interest expense	(3,869)	(4,164)	(11,733)	(12,185)
Allowance for funds used during construction	184	187	630	452
Other income	12,092	787	13,203	1,925
Other expense	(434)	(84)	(623)	(254)
Total other expense	11,842	890	13,210	2,123
Interest Expense
Interest on long-term debt	3,377	3,423	10,133	10,270
Other interest expense	492	741	1,600	1,915
Discontinued Operations, net of taxes
Net Income (Loss)	$ (8,961)	$ (10,039)	$ 37,557	$ 37,205

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

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Regulatory Assets and Liabilities (Tables) (Alabama Gas Corporation)

9 Months Ended

Sep. 30, 2013

Alabama Gas Corporation

Regulatory Assets and Liabilities [Line Items]

Schedule of Regulatory Assets and Liabilities

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

(in thousands)	September 30, 2013				December 31, 2012
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension assets	$	263	$	69,249	$	170	$	90,708
Accretion and depreciation for asset retirement obligation	—		17,579		—		16,536
Risk management activities	—		—		2,593		—
Rate recovery of asset removal costs, net	—		2,176		—		3,322
Gas supply adjustment	10,925		—		42,726		—
Other	25		—		26		—
Total regulatory assets	$	11,213	$	89,004	$	45,515	$	110,566
Regulatory liabilities:
RSE adjustment	$	6,573	$	—	$	1,740	$	—
Unbilled service margin	6,351		—		25,078		—
Postretirement liabilities	—		13,951		—		1,237
Refundable negative salvage	16,321		40,946		18,265		53,467
Gain on sale of property	10,890		—		—		—
Asset retirement obligation	—		25,772		—		24,930
Other	33		745		33		770
Total regulatory liabilities	$	40,168	$	81,414	$	45,116	$	80,404

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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2012, 2011 and 2010, included in the 2012 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items.

Derivatives

Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. The Company recognizes all derivatives on the balance sheet and measures all derivatives at fair value. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining six at September 30, 2013. The largest counterparty net loss position at September 30, 2013, Morgan Stanley Capital Group, constituted approximately $19.8 million of Energen Resources’ total net loss on fair value of derivatives. At September 30, 2013, Energen Resources was in a net gain position with Macquarie Bank Limited for approximately $10.0 million.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value is required to be recognized in operating revenues immediately. All other derivative transactions not previously qualified for cash flow hedge accounting are still considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These derivatives are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

Effective March 31, 2013 and June 30, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) and 2,353 MBbl, respectively, of various Permian Basin New York Mercantile Exchange (NYMEX) oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to the dedesignation date were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur.  Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues.

Effective June 30, 2013, the Company elected to discontinue the use of cash flow hedge accounting and to dedesignate all remaining derivative commodity instruments that were previously designated as cash flow hedges. As a result of discontinuing hedge accounting, any gains or losses from inception of the hedge to June 30, 2013 were frozen and will remain in accumulated other comprehensive income until the forecasted transactions actually occur. Any subsequent gains or losses will be accounted for as mark-to-market and recognized immediately through operating revenues. As a result of the Company’s election to discontinue hedge accounting, all derivative transactions entered into subsequent to June 30, 2013 will be accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.

Recently Issued Accounting Standards

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 3, Derivative Commodity Instruments.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 13, Accumulated Other Comprehensive Income (Loss).

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

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

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

[1] Includes $0.8 million and $4.7 million in mark-to-market gains for the three months and nine months ended September 30, 2013, respectively.

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

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

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

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Stock Compensation

9 Months Ended

Sep. 30, 2013

Share-based Compensation [Abstract]

Stock Compensation

STOCK COMPENSATION

Stock Incentive Plan

Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, restricted stock, performance shares or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 134,076 non-qualified option shares during the first quarter of 2013 with a grant-date fair value of $16.66.

Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted stock. In January 2013, 46,121 shares of restricted stock were awarded with a grant date fair value of $48.36. These awards were valued based on the quoted market price of the Company’s common stock at the date of grant and have a three year vesting period.

Performance Share Awards: The Stock Incentive Plan also provides for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Company common stock. Performance share awards are valued in a Monte Carlo model which uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. The Company granted 84,311 performance share awards during the first quarter of 2013 with a two year vesting period and a grant-date fair value of $59.19. The Company also granted 80,395 performance share awards during the first quarter of 2013 with a three year award period and a grant-date fair value of $60.81.

Stock Appreciation Rights Plan

The Energen Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 88,000 awards during the first quarter of 2013. These awards had a fair value of $39.10 as of September 30, 2013.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During the first quarter of 2013, Energen Resources awarded 33,796 Petrotech units with a fair value of $75.67 as of September 30, 2013, none of which included a market condition. Also awarded were 52,768 Petrotech units which included a market condition and had a fair value of $133.58 as of September 30, 2013. These awards have a three-year vesting period. During the third quarter of 2013, Energen Resources awarded 5,854 Petrotech units with a three-year vesting period and a fair value of $75.67 as of September 30, 2013, and 2,952 Petrotech units with a seventeen-month vesting period and a fair value of $75.88 as of September 30, 2013, none of which included a market condition.

Stock Repurchase Program

During the three months and nine months ended September 30, 2013, the Company had noncash purchases of approximately $0.8 million and $0.9 million, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

During the nine months ended September 30, 2013, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance as of December 31, 2012	$	118,023
Liabilities incurred	2,466
Liabilities settled	(542		)
Accretion expense (including discontinued operations of $944)	6,131
Reclassification associated with held for sale properties*	(19,474		)
Balance as of September 30, 2013	$	106,604

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

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Financial Instruments

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Financial Instruments

FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, was approximately $1,188.2 million and $1,255.8 million and both had a carrying value of $1,154.0 million at September 30, 2013 and December 31, 2012, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $262.8 million and $284.7 million and both had a carrying value of $250.0 million at September 30, 2013 and December 31, 2012, respectively. The fair values are based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company’s interest rate swap was a $2.1 million and a $3.3 million liability at September 30, 2013 and December 31, 2012, respectively, and is classified as Level 2 fair value liability. The fair value of the Company’s interest rate swap is recognized on a gross basis on the consolidated balance sheet.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2013 and December 31, 2012, Alagasco’s finance receivable totaled $10.8 million and $10.7 million, respectively. These finance receivables currently have an average balance of approximately $3,000 with terms of up to 84 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. Uncollected finance receivables are written off approximately 15 months after the account has been final billed. Alagasco had finance receivables past due 90 days or more of $0.7 million and $0.5 million as of September 30, 2013 and December 31, 2012, respectively.

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

(in thousands)
Allowance for credit losses as of December 31, 2012	$	470
Provision	191
Allowance for credit losses as of September 30, 2013	$	661

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Segment Information

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

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

	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2013			2012			2013			2012
Operating revenues from continuing operations
Oil and gas operations	$	272,038		$	214,620		$	875,350		$	799,339
Natural gas distribution	48,368			61,809			390,567			327,183
Total	$	320,406		$	276,429		$	1,265,917		$	1,126,522
Operating income (loss) from continuing operations
Oil and gas operations	$	18,607		$	26,913		$	181,948		$	280,897
Natural gas distribution	(22,544		)	(12,743		)	58,968			70,265
Eliminations and corporate expenses	(115		)	(206		)	(345		)	(857		)
Total	$	(4,052	)	$	13,964		$	240,571		$	350,305
Other income (expense)
Oil and gas operations	$	(13,209	)	$	(12,703	)	$	(38,686	)	$	(35,402	)
Natural gas distribution	7,973			(3,274		)	1,477			(10,062		)
Eliminations and other	175			186			405			390
Total	$	(5,061	)	$	(15,791	)	$	(36,804	)	$	(45,074	)
Income (loss) from continuing operations before income taxes	$	(9,113	)	$	(1,827	)	$	203,767		$	305,231

(in thousands)	September 30, 2013		December 31, 2012
Identifiable assets
Oil and gas operations	$	5,444,672	$	4,975,170
Natural gas distribution	1,127,487		1,177,134
Eliminations and other	42,713		23,586
Total	$	6,614,872	$	6,175,890

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

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

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

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Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Schedule of Quantifying Prior Year Misstatement Not Corrected Due to Materiality [Line Items]
Increase (decrease) in operating cash flow due to uncorrected error due to materiality	$ 1.9
Alabama Gas Corporation
Schedule of Quantifying Prior Year Misstatement Not Corrected Due to Materiality [Line Items]
Increase (decrease) in operating cash flow due to uncorrected error due to materiality	$ (0.8)

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Dispositions of Properties

9 Months Ended

Sep. 30, 2013

Extractive Industries [Abstract]

Dispositions of Properties

DISPOSITION OF PROPERTIES

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

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 7.5 million barrels of oil equivalent (MMBOE) through September 2017.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources’ total resulting exposure could be as much as $14 million depending on the contractor’s ability to remarket the drilling rig.

Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $185 million through September 2024. During both the nine months ending September 30, 2013 and 2012, Alagasco recognized approximately $36.8 million of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 146 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through October 2014 and an aggregate purchase price of $0.8 million with a market value of $0.8 million.

Income Taxes: The Company uses the liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities as well as tax credit carryforwards.  In accordance with Accounting Standards Codification 740-30-25-7, the Company has not recognized a deferred tax liability for the difference between the book basis and the tax basis in the stock of its subsidiaries. The unrecorded gross outside basis difference for Alagasco exceeds the recorded inside asset basis difference by approximately $35 million and would result in an additional deferred tax liability of $13 million.

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

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability.

Energen Resources previously disclosed an adverse judgment relating to the ownership of the company operated Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas.  Upon a Motion to Reconsider, the adverse judgment was vacated by the District Court in Ward County, Texas and a Summary Judgment Order dated July 30, 2013 was entered confirming Energen Resources’ superior title to the Cadenhead Well and its associated oil and gas leases.  The Summary Judgment Order has been appealed by the other party.

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

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $1.8 million of which $1.6 million has been incurred and $0.2 million has been reserved.

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the United States Environmental Protection Agency (EPA), Alagasco and the current site owner. In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the EPA’s investigation of a site which it refers to as the 35th Avenue Superfund Site located in Birmingham, Jefferson County, Alabama.  The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35th Avenue Superfund Site. In September 2013, Alagasco received from EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site.  The letter identifies Alagasco as a potentially responsible party (PRP) under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site.  The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination.  Alagasco has requested additional information from EPA regarding its designation as a PRP, and an opportunity to discuss this designation further with EPA. Alagasco is unable to determine the extent, if any, of its potential liability with respect to the proposed removal action and no amount has been accrued as of September 30, 2013.

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

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2013.

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Discontinued Operations

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

DISCONTINUED OPERATIONS

In October 2013, Energen Resources completed the sale of its Black Warrior Basin coalbed methane properties in Alabama for $160 million (subject to closing adjustments). The Company will record a pre-tax gain on the sale of approximately $35 million in the fourth quarter of 2013. The sale had an effective date of July 1, 2013 and the proceeds from the sale were used to repay short-term obligations. The property was classified as held-for sale and reflected in discontinued operations during the third quarter of 2013. At December 31, 2012, proved reserves associated with Energen’s Black Warrior Basin properties totaled 97 Bcf of natural gas.

During the third quarter of 2013, Energen Resources classified its North Louisiana/East Texas natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations and began marketing these assets. Energen Resources recognized a non-cash impairment writedown on these properties in the third quarter of 2013 of $24.6 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months and nine months ended September 30, 2013. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. This nonrecurring impairment writedown is classified as Level 3 fair value. The Company anticipates the sale being completed within the next twelve months and using the proceeds from the sale to repay short-term obligations. At December 31, 2012, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 20 Bcf of natural gas and 51 MBbl of oil.

The following table details held-for-sale properties by major classes of assets and liabilities:

(in thousands)	September 30, 2013
	Black Warrior Basin			North Louisiana/East Texas			Total
Accounts receivable	$	3,704		$	1,418		$	5,122
Inventories	1,078			63			1,141
Oil and gas properties	304,012			348,380			652,392
Less accumulated depreciation, depletion and amortization	(183,011		)	(293,935		)	(476,946		)
Other property, net	1,970			183			2,153
Total assets held-for-sale	127,753			56,109			183,862
Accounts payable	(1,713		)	(2		)	(1,715		)
Royalty payable	(792		)	(936		)	(1,728		)
Other current liabilities	(358		)	(35		)	(393		)
Other long-term liabilities	(5,377		)	(14,732		)	(20,109		)
Total liabilities held-for-sale	(8,240		)	(15,705		)	(23,945		)
Total held-for-sale properties	$	119,513		$	40,404		$	159,917

During the first quarter of 2012, Energen Resources recognized a non-cash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. This non-cash impairment writedown is reflected in loss from discontinued operations in the nine months ended September 30, 2012. The impairment was caused by the impact of lower future natural gas prices. This nonrecurring impairment writedown is classified as Level 3 fair value.

Gains and losses on the sale of certain oil and gas properties and any impairments of properties held-for-sale are reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. Accordingly, the results of operations for certain held-for-sale properties were reclassified and reported as discontinued operations for all prior periods presented. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale are reported at the lower of the carrying amount or fair value.

	Three months ended					Nine months ended
	September 30,					September 30,
(in thousands, except per share data)	2013			2012		2013			2012
Oil and gas revenues	$	18,258		$	18,895	$	55,483		$	57,601
Pretax income (loss) from discontinued operations	$	2,971		$	5,526	$	9,980		$	(6,028	)
Income tax expense (benefit)	1,105			1,975		3,711			(2,044		)
Income (Loss) From Discontinued Operations	$	1,866		$	3,551	$	6,269		$	(3,984	)
Loss on disposal of discontinued operations	$	(24,612	)	$	—	$	(24,612	)	$	—
Income tax benefit	(8,934		)	—		(8,934		)	—
Loss on Disposal of Discontinued Operations	$	(15,678	)	$	—	$	(15,678	)	$	—
Total Income (Loss) From Discontinued Operations	$	(13,812	)	$	3,551	$	(9,409	)	$	(3,984	)
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.05	)
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.05	)
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	0.03		$	0.05	$	0.09		$	(0.06	)
Loss on Disposal of Discontinued Operations	(0.22		)	—		(0.22		)	—
Total Income (Loss) From Discontinued Operations	$	(0.19	)	$	0.05	$	(0.13	)	$	(0.06	)

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Accumulated Other Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

The following table provides changes in the components of accumulated other comprehensive income (loss), net of the related income tax effects.

(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
Other comprehensive income (loss) before reclassifications	(10,924		)	4,157			(6,767		)
Amounts reclassified from accumulated other comprehensive income (loss)	(17,907		)	4,721			(13,186		)
Change in accumulated other comprehensive income (loss)	(28,831		)	8,878			(19,953		)
Balance as of September 30, 2013	$	15,365		$	(43,629	)	$	(28,264	)

The following table provides details of the reclassifications out of accumulated other comprehensive income (loss).

	Three months ended			Nine months ended
	September 30, 2013			September 30, 2013
(in thousands)	Amounts Reclassified						Line Item Where Presented
Gains and (losses) on cash flow hedges:
Commodity contracts	$	8,433		$	30,226		Operating revenues
Interest rate swap	(446		)	(1,282		)	Interest expense
Total cash flow hedges	7,987			28,944
Income tax expense	(3,048		)	(11,037		)
Net of tax	4,939			17,907
Pension and postretirement plans:
Transition obligation	(74		)	(220		)	Operations and maintenance
Prior service cost	(78		)	(235		)	Operations and maintenance
Actuarial losses*	(2,036		)	(6,387		)	Operations and maintenance
Actuarial losses on settlement charges*	(46		)	(421		)	Regulatory asset
Total pension and postretirement plans	(2,234		)	(7,263		)
Income tax expense	783			2,542
Net of tax	(1,451		)	(4,721		)
Total reclassifications for the period	$	3,488		$	13,186

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

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

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Recently Issued Accounting Standards

9 Months Ended

Sep. 30, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued ASU No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities. The effective date and transition of the disclosure requirement in ASU No. 2011-11 remained unchanged. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 3, Derivative Commodity Instruments.

In February 2013, the FASB issued ASU No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This update requires companies to include reclassification adjustments for items that are reclassified from other comprehensive income to net income in a single note or on the face of the financial statements. The amendment was effective for annual and interim reporting periods beginning after December 15, 2012. The adoption of this standard did not have a material impact on the consolidated financial statements of the Company. The additional disclosures are included in Note 13, Accumulated Other Comprehensive Income (Loss).