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 MARCH 31, 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 May 1, 2013.

Energen Corporation	$0.01 par value	72,222,501 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 MARCH 31, 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	27
	Selected Business Segment Data of Energen Corporation	36
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	39
PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 6.	Exhibits	40
SIGNATURES		41

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended
	March 31,
(in thousands, except per share data)	2013			2012
Operating Revenues
Oil and gas operations	$	254,994		$	223,957
Natural gas distribution	237,685			194,487
Total operating revenues	492,679			418,444
Operating Expenses
Cost of gas	95,442			59,586
Operations and maintenance	145,837			110,561
Depreciation, depletion and amortization	115,295			94,534
Asset impairment	—			21,545
Taxes, other than income taxes	28,772			26,235
Accretion expense	1,997			1,813
Total operating expenses	387,343			314,274
Operating Income	105,336			104,170
Other Income (Expense)
Interest expense	(16,754		)	(15,425		)
Other income	1,758			2,032
Other expense	(69		)	(113		)
Total other expense	(15,065		)	(13,506		)
Income Before Income Taxes	90,271			90,664
Income tax expense	33,579			33,258
Net Income	$	56,692		$	57,406
Diluted Earnings Per Average Common Share	$	0.78		$	0.79
Basic Earnings Per Average Common Share	$	0.79		$	0.80
Dividends Per Common Share	$	0.145		$	0.140
Diluted Average Common Shares Outstanding	72,288			72,326
Basic Average Common Shares Outstanding	72,143			72,102

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
	March 31,
(in thousands)	2013			2012
Net Income	$	56,692		$	57,406
Other comprehensive income (loss):
Cash flow hedges:
Current period change in fair value of commodity derivative instruments, net of tax of ($16,424) and ($7,498)	(26,798		)	(12,234		)
Reclassification adjustment for commodity derivative instruments, net of tax of ($6,570) and $302	(10,720		)	493
Current period change in fair value of interest rate swap, net of tax of ($11) and ($265)	(20		)	(492		)
Reclassification adjustment for interest rate swap, net of tax of $143 and $137	266			254
Total cash flow hedges	(37,272		)	(11,979		)
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $26 and $25	48			47
Amortization of prior service cost, net of taxes of $27 and $30	51			55
Amortization of net loss, including settlement charges, net of taxes of $920 and $412	1,709			766
Total pension and postretirement plans	1,808			868
Comprehensive Income	$	21,228		$	46,295

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

4

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	March 31, 2013		December 31, 2012
ASSETS
Current Assets
Cash and cash equivalents	$	20,303	$	9,704
Accounts receivable, net of allowance for doubtful accounts of $5,446 at March 31, 2013, and $6,549 at December 31, 2012	241,507		277,900
Inventories
Storage gas inventory	9,264		32,205
Materials and supplies	25,283		28,291
Liquified natural gas in storage	3,109		3,498
Regulatory asset	24,135		45,515
Income tax receivable	1,883		6,664
Deferred income taxes	27,278		8,520
Prepayments and other	12,084		12,823
Total current assets	364,846		425,120
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,712,635		6,439,127
Less accumulated depreciation, depletion and amortization	1,858,960		1,765,241
Oil and gas properties, net	4,853,675		4,673,886
Utility plant	1,435,924		1,416,590
Less accumulated depreciation	583,625		573,947
Utility plant, net	852,299		842,643
Other property, net	25,218		25,107
Total property, plant and equipment, net	5,731,192		5,541,636
Other Assets
Regulatory asset	109,002		110,566
Other postretirement assets	1,732		1,404
Long-term derivative instruments	26,199		40,577
Deferred charges and other	60,207		56,587
Total other assets	197,140		209,134
TOTAL ASSETS	$	6,293,178	$	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)	March 31, 2013			December 31, 2012
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	75,000		$	50,000
Notes payable to banks	712,000			643,000
Accounts payable	285,920			257,579
Accrued taxes	38,666			30,076
Customers' deposits	25,231			24,705
Amounts due customers	10,580			19,718
Accrued wages and benefits	17,587			24,984
Regulatory liability	41,886			45,116
Royalty payable	38,771			34,426
Other	27,344			30,178
Total current liabilities	1,272,985			1,159,782
Long-term debt	1,078,529			1,103,528
Deferred Credits and Other Liabilities
Asset retirement obligation	120,599			118,023
Pension and other postretirement liabilities	106,515			110,282
Regulatory liability	68,812			80,404
Long-term derivative instruments	9,705			11,305
Deferred income taxes	931,628			905,601
Other	12,981			10,275
Total deferred credits and other liabilities	1,250,240			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, 75,083,108 shares issued at March 31, 2013, and 75,067,760 shares issued at December 31, 2012	751			751
Premium on capital stock	493,928			492,108
Capital surplus	2,802			2,802
Retained earnings	2,360,274			2,314,055
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	8,834			46,352
Pension and postretirement plans	(50,699		)	(52,507		)
Interest rate swap	(1,910		)	(2,156		)
Deferred compensation plan	3,416			2,774
Treasury stock, at cost: 2,969,784 shares at March 31, 2013, and 2,998,620 shares at December 31, 2012	(125,972		)	(127,489		)
Total shareholders' equity	2,691,424			2,676,690
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,293,178		$	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)
Three months ended March 31, (in thousands)	2013			2012
Operating Activities
Net income	$	56,692		$	57,406
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	115,295			94,534
Asset impairment	—			21,545
Accretion expense	1,997			1,813
Deferred income taxes	29,028			23,182
Bad debt expense (recovery)	218			(258		)
Exploratory expense	541			1,076
Change in derivative fair value	37,977			47,221
(Gain) loss on sale of assets	(656		)	47
Other, net	11,078			4,261
Net change in:
Accounts receivable	(35,312		)	20,063
Inventories	26,338			1,473
Accounts payable	9,670			7,327
Amounts due customers, including gas supply pass-through	10,254			(31,926		)
Income tax receivable	4,781			5,852
Pension and other postretirement benefit contributions	(10,334		)	(3,176		)
Other current assets and liabilities	3,886			(19,460		)
Net cash provided by operating activities	261,453			230,980
Investing Activities
Additions to property, plant and equipment	(297,301		)	(276,791		)
Acquisitions, net of cash acquired	(13,146		)	(68,176		)
Proceeds from sale of assets	1,370			13,766
Other, net	(362		)	(375		)
Net cash used in investing activities	(309,439		)	(331,576		)
Financing Activities
Payment of dividends on common stock	(10,473		)	(10,095		)
Issuance of common stock	—			604
Payment of long-term debt	(10		)	(25		)
Net change in short-term debt	69,000			150,000
Tax benefit on stock compensation	68			227
Other	—			(38		)
Net cash provided by financing activities	58,585			140,673
Net change in cash and cash equivalents	10,599			40,077
Cash and cash equivalents at beginning of period	9,704			9,541
Cash and Cash Equivalents at End of Period	$	20,303		$	49,618

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
	March 31,
(in thousands)	2013			2012
Operating Revenues	$	237,685		$	194,487
Operating Expenses
Cost of gas	95,442			59,586
Operations and maintenance	38,017			34,066
Depreciation and amortization	10,729			10,446
Income taxes
Current	25,921			25,440
Deferred	3,020			3,198
Taxes, other than income taxes	14,204			11,829
Total operating expenses	187,333			144,565
Operating Income	50,352			49,922
Other Income (Expense)
Allowance for funds used during construction	219			134
Other income	750			986
Other expense	(69		)	(62		)
Total other income	900			1,058
Interest Expense
Interest on long-term debt	3,378			3,424
Other interest expense	652			638
Total interest expense	4,030			4,062
Net Income	$	47,222		$	46,918

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

8

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	March 31, 2013			December 31, 2012
ASSETS
Property, Plant and Equipment
Utility plant	$	1,435,924		$	1,416,590
Less accumulated depreciation	583,625			573,947
Utility plant, net	852,299			842,643
Other property, net	41			42
Current Assets
Cash and cash equivalents	17,260			5,559
Accounts receivable
Gas	99,657			94,011
Other	5,698			5,117
Affiliated companies	4,620			5,742
Allowance for doubtful accounts	(4,600		)	(5,700		)
Inventories
Storage gas inventory	9,264			32,205
Materials and supplies	5,541			5,528
Liquified natural gas in storage	3,109			3,498
Regulatory asset	24,135			45,515
Income tax receivable	—			2,762
Deferred income taxes	18,669			18,799
Prepayments and other	3,674			4,451
Total current assets	187,027			217,487
Other Assets
Regulatory asset	109,002			110,566
Pension and other postretirement assets	1,103			848
Deferred charges and other	11,098			11,290
Total other assets	121,203			122,704
TOTAL ASSETS	$	1,160,570		$	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)	March 31, 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 March 31, 2013 and December 31, 2012	20		20
Premium on capital stock	31,682		31,682
Capital surplus	2,802		2,802
Retained earnings	364,783		325,999
Total common shareholder's equity	399,287		360,503
Long-term debt	250,018		250,028
Total capitalization	649,305		610,531
Current Liabilities
Notes payable to banks	30,000		77,000
Accounts payable	38,264		51,741
Accrued taxes	47,068		24,186
Customers' deposits	25,231		24,705
Amounts due customers	10,580		19,718
Accrued wages and benefits	6,184		6,703
Regulatory liability	41,886		45,116
Other	9,535		9,018
Total current liabilities	208,748		258,187
Deferred Credits and Other Liabilities
Deferred income taxes	192,271		189,381
Pension and other postretirement liabilities	39,914		43,611
Regulatory liability	68,812		80,404
Other	1,520		762
Total deferred credits and other liabilities	302,517		314,158
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,160,570	$	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)
Three months ended March 31, (in thousands)	2013			2012
Operating Activities
Net income	$	47,222		$	46,918
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	10,729			10,446
Deferred income taxes	3,020			3,198
Bad debt expense (recovery)	217			(258		)
Other, net	3,685			(2,564		)
Net change in:
Accounts receivable	(23,409		)	14,706
Inventories	23,317			5,985
Accounts payable	(11,306		)	(20,364		)
Amounts due customers, including gas supply pass-through	10,254			(31,926		)
Income tax receivable	2,762			8,374
Pension and other postretirement benefit contributions	(5,365		)	(681		)
Other current assets and liabilities	24,183			11,425
Net cash provided by operating activities	85,309			45,259
Investing Activities
Additions to property, plant and equipment	(19,046		)	(14,245		)
Other, net	886			(767		)
Net cash used in investing activities	(18,160		)	(15,012		)
Financing Activities
Dividends	(8,438		)	(8,027		)
Payment of long-term debt	(10		)	(25		)
Net change in short-term debt	(47,000		)	10,000
Other	—			(38		)
Net cash provided by (used in) financing activities	(55,448		)	1,910
Net change in cash and cash equivalents	11,701			32,157
Cash and cash equivalents at beginning of period	5,559			7,817
Cash and Cash Equivalents at End of Period	$	17,260		$	39,974

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.

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 quarter ended March 31, 2012 resulted in a decrease of $3.9 million and $4.5 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 caused no impact to 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. RSE’s current extension is for a seven-year period through December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology.

Alagasco's allowed range of return on average common equity is 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months ended March 31, 2013, Alagasco had a net $2.4 million pre-tax 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 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) 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, 2012 and 2011.

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;

12

(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, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments 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. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net loss position with six of its active counterparties at March 31, 2013. The two largest counterparty net loss positions at March 31, 2013, Morgan Stanley Capital Group, Inc and Barclays Bank PLC, constituted approximately $24.7 million and $5.1 million, respectively, of Energen Resources’ total net loss on fair value of derivatives. Energen Resources was in a net gain position with seven of its active counterparties at March 31, 2013. The two largest counterparty net gain positions at March 31, 2013, Macquarie Bank Limited and BP Corporation North America Inc., constituted approximately $10.3 million and $5.3 million, respectively, of Energen Resources’ net gain on fair value of derivatives.

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 March 31, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change. Effective March 31, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) of various Permian Basin NYMEX oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to March 31, 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.

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

(in thousands)	March 31, 2013
	Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	51,277			$	—	$	51,277
Long-term asset derivative instruments	25,921				—		25,921
Total derivative assets	77,198				—		77,198
Accounts receivable	(36,245		)	*	—		(36,245		)
Long-term asset derivative instruments	(6,594		)	*	—		(6,594		)
Accounts payable	(11,983		)		—		(11,983		)
Long-term liability derivative instruments	(7,275		)		—		(7,275		)
Total derivative liabilities	(62,097		)		—		(62,097		)
Total derivatives designated	15,101				—		15,101
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(4,342		)	*	—		(4,342		)
Long-term asset derivative instruments	6,872				—		6,872
Total derivative assets	2,530				—		2,530
Accounts payable	(20,816		)		—		(20,816		)
Long-term liability derivative instruments	(1,074		)		—		(1,074		)
Total derivative liabilities	(21,890		)		—		(21,890		)
Total derivatives not designated	(19,360		)		—		(19,360		)
Total derivatives	$	(4,259	)		$	—	$	(4,259	)

(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 $5.4 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 March 31, 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 March 31, 2013			Three months ended March 31, 2012
Loss recognized in OCI on derivatives (effective portion), net of tax of ($16.4) million and ($7.5) million	—	$	(26,798	)	$	(12,234	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	17,824		$	1,872
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(534	)	$	(2,666	)

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 March 31, 2013			Three months ended March 31, 2012
Loss recognized in income on derivatives	Operating revenues	$	(31,501	)	$	(44,005	)

As of March 31, 2013, $1.6 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. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of March 31, 2013, the Company had 4.2 billion cubic feet (Bcf) and 9.7 Bcf of natural gas hedges which expire during 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 10.5 million barrels (MMBbl), 8.2 MMBbl and 0.7 MMBbl of oil and oil basis hedges which expire during 2013, 2014 and 2015, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2013 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges.

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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	9.4	Bcf	$4.83 Mcf	NYMEX Swaps
	24.4	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	3.4	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Oil
2013	6,752	MBbl	$90.99 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	720	MBbl	$90.10 Bbl	NYMEX Swaps
Oil Basis Differential
2013	2,701	MBbl	$(3.02) Bbl	WTS/WTI Basis Swaps*
	2,995	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	33.9	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 March 31, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010. 

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

	March 31, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(12,452	)	$	23,142		$	10,690
Noncurrent assets	12,194			14,005			26,199
Current liabilities	(24,834		)	(7,965		)	(32,799		)
Noncurrent liabilities	(5,626		)	(2,723		)	(8,349		)
Net derivative asset (liability)	$	(30,718	)	$	26,459		$	(4,259	)

	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 March 31, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which are classified as Level 2 fair values and are 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 $28 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $5.2 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)	March 31, 2013			March 31, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	27,107			13,181
Unrealized gains (losses) relating to instruments held at the reporting date*	(63,482		)	39,767
Settlements during period	(26,185		)	(13,826		)
Balance at end of period	$	26,459		$	104,923

*Includes $12.4 million in mark-to-market losses and $3.8 million in mark-to-market gains for the three months ended March 31, 2013 and 2012.

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

(in thousands)	Fair Value as of March 31, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	14,529		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
2014	$	16,066		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
Natural Gas Basis - Permian
2013	$	(1,854	)	Discounted Cash Flow	Forward Basis	($0.12) Mcf
2014	$	(2,731	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf
Oil Basis - WTS/WTI
2013	$	(6,209	)	Discounted Cash Flow	Forward Basis	($0.66) Bbl
Oil Basis - WTI/WTI
2013	$	(2,207	)	Discounted Cash Flow	Forward Basis	($0.18 - $0.28) Bbl
Natural Gas Liquids
2013	$	8,865		Discounted Cash Flow	Forward Price	$0.75 - $0.83 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.

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

	March 31, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	79,728	$	(42,839	)	$	36,889	$	—	$	—	$	36,889
Derivative liabilities	$	83,987	$	(42,839	)	$	41,148	$	—	$	—	$	41,148

	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

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended					Three months ended
(in thousands, except per share amounts)	March 31, 2013					March 31, 2012
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	56,692	72,143	$	0.79	$	57,406	72,102	$	0.80
Effect of dilutive securities
Stock options			144					216
Non-vested restricted stock			1					8
Diluted EPS	$	56,692	72,288	$	0.78	$	57,406	72,326	$	0.79

For the three months ended March 31, 2013 and 2012 the Company had 988,087 and 849,583 options, respectively, that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months ended March 31, 2013, the Company had 161,249performance share awards that were excluded from the computation of diluted EPS. For the three months ended March 31, 2012, the Company had no performance share awards that were excluded from the computation of diluted EPS. For the three months ended March 31, 2013 and 2012, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

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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
	March 31,
(in thousands)	2013			2012
Operating revenues
Oil and gas operations	$	254,994		$	223,957
Natural gas distribution	237,685			194,487
Total	$	492,679		$	418,444
Operating income (loss)
Oil and gas operations	$	26,327		$	26,005
Natural gas distribution	79,293			78,560
Eliminations and corporate expenses	(284		)	(395		)
Total	$	105,336		$	104,170
Other income (expense)
Oil and gas operations	$	(11,993	)	$	(10,558	)
Natural gas distribution	(3,130		)	(3,004		)
Eliminations and other	58			56
Total	$	(15,065	)	$	(13,506	)
Income before income taxes	$	90,271		$	90,664

(in thousands)	March 31, 2013		December 31, 2012
Identifiable assets
Oil and gas operations	$	5,100,983	$	4,975,170
Natural gas distribution	1,155,950		1,177,134
Eliminations and other	36,245		23,586
Total	$	6,293,178	$	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 provided 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 provided for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provided that payment of earned performance share awards be made in the form of Company common stock. The Company estimated fair value of performance share awards based on the quoted market price of the Company's common stock and adjusted each period for the expected payout ratio. 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.

2004 Stock Appreciation Rights Plan

The Energen 2004 Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 88,000 awards during the first quarter of 2013. These awards had a fair value of $20.05 as of March 31, 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 three months ended March 31, 2013, Energen Resources awarded 33,796 Petrotech units, none of which included a market condition, with a fair value of $50.45 as of March 31, 2013. Also awarded were 52,768 Petrotech units which included a market condition and had a fair value of $70.39 as of March 31, 2013. These awards have a three-year vesting period.

Stock Repurchase Program

During the three months ended March 31, 2013, the Company had noncash purchases of approximately $71,000 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 March 31,
(in thousands)	2013			2012
Components of net periodic benefit cost:
Service cost	$	3,602		$	2,632
Interest cost	2,718			2,700
Expected long-term return on assets	(3,713		)	(3,563		)
Actuarial loss	3,690			2,099
Prior service cost amortization	122			129
Settlement charge	144			—
Net periodic expense	$	6,563		$	3,997

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 currently expected to be made to the pension plans by the Company during 2013. For the three months ending March 31, 2013, the Company made benefit payments aggregating $0.9 million to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $2.9 million 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.

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

	Three months ended March 31,
(in thousands)	2013			2012
Components of net periodic benefit cost:
Service cost	$	444		$	463
Interest cost	869			1,062
Expected long-term return on assets	(1,242		)	(1,109		)
Actuarial loss	—			9
Transition amortization	324			479
Net periodic expense	$	395		$	904

For the three months ended March 31, 2013, the Company made contributions aggregating $0.5 million to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $1.1 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 29.6 million barrels of oil equivalent (MMBOE) through November 2021.

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 $19 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 $94 million through September 2024. During the three months ending March 31, 2013 and 2012, Alagasco recognized approximately $14.4 million and $14.3 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 158 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At March 31, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through January 2014 and an aggregate purchase price of $1.1 million with a market value of $1.2 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.

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On November 2, 2011, Energen Resources spudded the Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. During the drilling phase, Chesapeake Exploration, LLC, notified Energen Resources that it believed it was the owner of the lease from which the Cadenhead Well was producing. Shortly thereafter, Energen Resources filed a declaratory judgment action in the District Court of Ward County, Texas to resolve the title dispute. Energen Resources has a fifty percent working interest in the Cadenhead Well. The Cadenhead Well produced approximately 63 net MBOE in 2012 and is expected to produce approximately 34 net MBOE in 2013. On January 18, 2013, a judgment was entered which was adverse to Energen Resources' claim of ownership. The Company believes the adverse ruling was incorrect, and plans to vigorously pursue all available avenues of appeal.

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.

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 May 2012, Alagasco received from the EPA a Request for Information Pursuant to Section 104 of CERCLA relating to the EPA's investigation of a site which it refers to as the 35^th Avenue Superfund Site in and around Birmingham, Jefferson County, Alabama. The inquiry requests information about a parcel owned by Alagasco and located in the vicinity of the 35^th Avenue site. The parcel is the former site of a manufactured gas distribution facility. Alagasco has responded to the inquiry.

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

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company's New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of March 31, 2013.

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, approximates $1,216.9 million and $1,255.8 million and has a carrying value of $1,154.0 million and $1,154.0 million at March 31, 2013 and December 31, 2012, respectively. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $271.3 million and $284.7 million and has a carrying value of $250.0 million and $250.0 million at March 31, 2013 and December 31, 2012, respectively. The fair values were 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 $2.9 million and a $3.3 million liability at March 31, 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.

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Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At March 31, 2013 and December 31, 2012, Alagasco’s finance receivable totaled $10.4 million and $10.7 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.6 million and $0.5 million as of March 31, 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	116
Allowance for credit losses as of March 31, 2013	$	586

10. REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	March 31, 2013				December 31, 2012
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	253	$	89,316	$	170	$	90,708
Accretion and depreciation for asset retirement obligation	—		16,884		—		16,536
Risk management activities	—		—		2,593		—
Rate recovery of asset removal costs, net	—		2,802		—		3,322
Gas supply adjustment	23,857		—		42,726		—
Other	25		—		26		—
Total regulatory assets	$	24,135	$	109,002	$	45,515	$	110,566
Regulatory liabilities:
RSE adjustment	$	2,262	$	—	$	1,740	$	—
Unbilled service margin	22,108		—		25,078		—
Postretirement liabilities	—		1,487		—		1,237
Refundable negative salvage	17,483		41,352		18,265		53,467
Asset retirement obligation	—		25,211		—		24,930
Other	33		762		33		770
Total regulatory liabilities	$	41,886	$	68,812	$	45,116	$	80,404

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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 three months ended March 31, 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	901
Liabilities settled	(322		)
Accretion expense	1,997
Balance as of March 31, 2013	$	120,599

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 $25.2 million and $24.9 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of March 31, 2013 and December 31, 2012, respectively. Regulatory assets for accumulated asset removal costs of $2.8 million and $3.3 million as of March 31, 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.

12. ACQUISITION AND DISPOSITION OF PROPERTIES

During the first quarter of 2013, Alagasco entered into a purchase and sale agreement to sell its Birmingham Metro Operations Center which is located on 11.7 acres in downtown Birmingham and has been in service since the 1940's. The sales price is approximately $14 million and the sale is expected to close in August of 2013. Effective upon closing, Alagasco plans to lease the facility from the purchaser for a period of approximately 18 months.

During the first quarter of 2012, Energen Resources recognized a noncash 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. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

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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	(26,818		)	—			(26,818		)
Amounts reclassified from accumulated other comprehensive income (loss)	(10,454		)	1,808			(8,646		)
Change in accumulated other comprehensive income (loss)	(37,272		)	1,808			(35,464		)
Balance as of March 31, 2013	$	6,924		$	(50,699	)	$	(43,775	)

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

	Three months ended
	March 31, 2013
(in thousands)	Amounts Reclassified			Line Item Where Presented
Gains and (losses) on cash flow hedges:
Commodity contracts	$	17,290		Operating revenues
Interest rate swap	(409		)	Interest expense
Total cash flow hedges	16,881
Income tax expense	(6,427		)
Net of tax	10,454
Pension and postretirement plans:
Transition obligation	(74		)	Operations and maintenance
Prior service cost	(78		)	Operations and maintenance
Actuarial losses*	(2,254		)	Operations and maintenance
Actuarial losses on settlement charges*	(375		)	Regulatory asset
Total pension and postretirment plans	(2,781		)
Income tax expense	973
Net of tax	(1,808		)
Total reclassifications for the period	$	8,646

* In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the 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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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).

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

RESULTS OF OPERATIONS

Energen's net income totaled $56.7 million ($0.78 per diluted share) for the three months ended March 31, 2013 compared with net income of $57.4 million ($0.79 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended March 31, 2013, of $8.8 million as compared with $9.5 million in the same quarter in the previous year. This decrease in net income was primarily the result of increased lease operating expense excluding production taxes (approximately $16 million after-tax), higher depreciation, depletion and amortization (DD&A) expense (approximately $13 million after-tax), higher administrative expense (approximately $4 million after-tax), lower natural gas production volumes (approximately $4 million after-tax), decreased natural gas liquids commodity prices (approximately $2 million after-tax), and a year-over-year after-tax $0.7 million non-cash mark-to-market decrease in derivatives (resulting from an after-tax $26 million non-cash mark-to-market loss on derivatives for the first quarter of 2013 and an after-tax $25.3 million non-cash mark-to-market loss on derivatives for the first quarter of 2012). Positively affecting net income was the impact of higher oil and natural gas liquids production volumes (approximately $20 million after-tax), increased natural gas and oil commodity prices (approximately $4 million after-tax) and a noncash impairment in the first quarter of 2012 on certain natural gas properties in East Texas of approximately $13.4 million after-tax. Energen's natural gas utility, Alagasco, reported net income of $47.2 million in the first quarter of 2013 compared to net income of $46.9 million in the same period last year. This increase primarily reflects the utility’s ability to earn on a higher level of equity in support of Alagasco's investment in its distribution system and support systems devoted to public service.

Oil and Gas Operations

Revenues from oil and gas operations rose 13.9 percent to $255.0 million for the three months ended March 31, 2013 largely as a result of higher oil and natural gas liquids production volumes combined with increased realized natural gas and oil commodity prices partially offset by lower natural gas production volumes and decreased realized natural gas liquids commodity prices. During the current quarter, revenue per unit of production for natural gas increased 8.4 percent to $4.27 per thousand cubic feet (Mcf), while oil revenue per unit of production rose slightly to $85.66 per barrel. Natural gas liquids revenue per unit of production fell 11.5 percent to an average price of $0.77 per gallon. Revenues per unit of production include realized prices and the effects of designated cash flow hedges and exclude the impact of the mark-to-market hedges.

Production for the current quarter 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 first quarter declined 7.4 percent to 17.7 billion cubic feet (Bcf), oil volumes increased 18.6 percent to 2,317 thousand barrels (MBbl) and natural gas liquids production rose 6.2 percent to 27.6 million gallons (MMgal). Oil and natural gas liquids comprised approximately 50 percent of Energen Resources' production for the current quarter.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. Energen Resources recorded a pre-tax gain of $0.7 million in the first quarter of 2013 from the sale of various Permian Basin properties. Energen Resources recorded no property sales in the first quarter of 2012.

Operations and maintenance (O&M) expense increased $31.4 million for the quarter. 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 $24.9 million for the quarter largely due to additional workover and repair expense (approximately $10.7 million), increased water disposal costs (approximately $3.5 million), higher ad valorem taxes (approximately $3.5 million), additional equipment rental expense(approximately $3.4 million), increased gathering costs (approximately $1.3 million) and increased chemical and treatment costs (approximately $1.1 million). On a per unit basis, the average lease operating expense (excluding production taxes) for the current quarter was $13.77 per barrel of oil equivalent (BOE) as compared to $9.84 per BOE in the same period a year ago. Administrative expense increased $6.8 million for the three months ended March 31, 2013 largely due to higher labor costs (approximately $2.9 million) and increased costs from the Company’s benefit and performance-based compensation plans (approximately $2.6 million). Exploration expense fell $0.3 million in the first quarter of 2013.

Energen Resources' DD&A expense for the quarter increased $20.5 million, excluding the prior year impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of certain properties to their fair value based on expected future discounted cash flows. The average depletion rate for the current quarter was $17.46 per BOE as compared to

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$14.44 per BOE, excluding the asset impairment, in the same period a year ago. The increase in the current quarter per unit DD&A rate, which contributed approximately $17.9 million to the increase in DD&A expense, was largely due to higher rates resulting from an increase in development costs. Higher production volumes contributed approximately $2.4 million to the increase in DD&A expense for the quarter.

Energen Resources' expense for taxes other than income taxes was $0.2 million higher in the three months ended March 31, 2013 largely due to production-related taxes. Higher oil and natural gas liquids commodity production volumes contributed approximately $0.4 million to the increase in production-related taxes partially offset by a decrease of approximately $0.2 million primarily due to lower net commodity market prices. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues increased $43.2 million for the quarter largely due to higher gas costs and an increase in customer usage partially offset by adjustments from the utility’s rate setting mechanisms. During the first quarter of 2013, Alagasco had a net $2.4 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the quarter, weather that was 28.7 percent colder than in the same quarter in the prior year contributed to a 26 percent increase in residential sales volumes and a 22.2 percent rise in commercial and industrial customer sales volumes. Transportation volumes increased 6.3 percent in period comparisons. Higher gas costs combined with an increase in gas purchase volumes resulted in a 60.2 percent increase in cost of gas for the quarter. 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 rose 11.6 percent in the current quarter primarily due to higher labor-related costs (approximately $1.9 million), additional distribution operation expenses (approximately $1 million), higher bad debt expense (approximately $0.5 million) and increased business development and marketing expense (approximately $0.4 million).

A 2.7 percent increase in depreciation expense in the current quarter 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 $1.3 million in the first quarter of 2013 largely due to higher short-term borrowings. Income tax expense for the Company increased $0.3 million in the current quarter.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $261.5 million as compared to $231.0 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. Working capital needs at Alagasco were additionally affected by higher gas costs and changes to storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $309.4 million for the three months ended March 31, 2013 primarily due to additions of property, plant and equipment of $310 million. Energen Resources incurred on a cash basis $291 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. Utility capital expenditures on a cash basis totaled $19.0 million year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities and information systems.

The Company provided net cash of $58.6 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.

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 $1,015 million, including $795 million for existing properties, including exploration to date of $96 million. On an annual basis, the development and exploration expenditures cannot be reasonably

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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.

Impairment

During the first quarter of 2012, Energen Resources recognized a noncash 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. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. 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) and is allowed to earn a range of return of 13.15 percent to 13.65 percent on average common equity throughout the term of the Rate Stabilization and Equalization (RSE) order. The Company’s current RSE order has a term extending through December 31, 2014. At its March 2013 monthly meeting, the APSC announced the schedule for a series of public informal proceedings to review the Company’s RSE mechanism. The Company expects discussion topics to include allowed range of return on equity and the term length of renewals. The public proceedings are scheduled to occur on September 5, September 25, October 9 and November 13, 2013. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. 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. Refunds of negative salvage costs to customers through lower tariff rates were $12.9 million, $14.2 million, $22.2 million and $2.7 million for the periods January through March 2013, January through December 2012, January through December 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $17.5 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $41.4 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 March 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 three months ended March 31, 2013, Alagasco reduced the bad debt reserve by approximately $1.1 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 $28 million in 2013 but will vary depending upon the price of natural gas. During 2013, Alagasco plans to invest an estimated $75 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

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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.

During the first quarter of 2013, Alagasco entered into a purchase and sale agreement to sell its Birmingham Metro Operations Center which is located on 11.7 acres in downtown Birmingham and has been in service since the 1940's. The sales price is approximately $14 million and the sale is expected to close in August of 2013. Effective upon closing, Alagasco plans to lease the facility from the purchaser for a period of approximately 18 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 March 31, 2013, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net loss position with six of its active counterparties and in a net gain with the remaining seven at March 31, 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.

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	9.4	Bcf	$4.83 Mcf	NYMEX Swaps
	24.4	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	2.5	Bcf*	$4.17 Mcf	Basin Specific Swaps - San Juan
	3.4	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
	1.1	Bcf*	$4.16 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	5.8	Bcf*	$4.06 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Oil
2013	6,752	MBbl	$90.99 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	720	MBbl	$90.10 Bbl	NYMEX Swaps
Oil Basis Differential
2013	2,701	MBbl	$(3.02) Bbl	WTS/WTI Basis Swaps**
	2,995	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps***
Natural Gas Liquids
2013	33.9	MMGal	$1.02 Gal	Liquids Swaps
* Contract entered into subsequent to March 31, 2013
**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.

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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:

	March 31, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(12,452	)	$	23,142		$	10,690
Noncurrent assets	12,194			14,005			26,199
Current liabilities	(24,834		)	(7,965		)	(32,799		)
Noncurrent liabilities	(5,626		)	(2,723		)	(8,349		)
Net derivative asset (liability)	$	(30,718	)	$	26,459		$	(4,259	)

	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 March 31, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which are classified as Level 2 fair values and are 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 March 31, 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 $28 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $5.2 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.

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At March 31, 2013, the Company reported negative working capital of $908.2 million arising from current liabilities of $1,273.0 million exceeding current assets of $364.8 million. The negative working capital is primarily due to a $69 million in increase in borrowings during the first quarter of 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. 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 March 31, 2013 include $10.7 million and $32.8 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 $17.5 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 its 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.

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 March 31, 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 will recognize 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.

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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.

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.

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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 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.

34

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
	March 31,
(in thousands, except sales price data)	2013			2012
Oil and Gas Operations
Operating revenues
Natural gas	$	71,072		$	75,580
Oil	161,812			124,314
Natural gas liquids	21,116			23,712
Other	994			351
Total	$	254,994		$	223,957
Non-cash mark-to-market gains (losses) included in operating revenues above
Natural gas	$	(4,375	)	$	283
Oil	(36,652		)	(41,920		)
Natural gas liquids	(21		)	965
Total	$	(41,048	)	$	(40,672	)
Production volumes
Natural gas (MMcf)	17,688			19,092
Oil (MBbl)	2,317			1,953
Natural gas liquids (MMgal)	27.6			26.0
Total production volumes (MBOE)	5,921			5,755
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf)	$	4.27		$	3.94
Oil (barrel)	$	85.66		$	85.12
Natural gas liquids (gallon)	$	0.77		$	0.87
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.31		$	2.67
Oil (barrel)	$	82.44		$	98.58
Natural gas liquids (gallon)	$	0.68		$	0.95
Other data
Lease operating expense
Lease operating expense and other	$	81,546		$	56,612
Production taxes	14,363			14,162
Total	$	95,909		$	70,774
Depreciation, depletion and amortization	$	104,566		$	84,088
Asset impairment	$	—		$	21,545
Capital expenditures	$	285,053		$	340,967
Exploration expense	$	1,500		$	1,789
Operating income	$	26,327		$	26,005

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Natural Gas Distribution
Operating revenues
Residential	$	162,739		$	130,509
Commercial and industrial	57,599			46,756
Transportation	18,240			15,598
Other	(893		)	1,624
Total	$	237,685		$	194,487
Gas delivery volumes (MMcf)
Residential	10,382			8,238
Commercial and industrial	4,207			3,442
Transportation	12,790			12,036
Total	27,379			23,716
Other data
Depreciation and amortization	$	10,729		$	10,446
Capital expenditures	$	19,697		$	14,943
Operating income	$	79,293		$	78,560

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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 cash flow hedge, as well as its risk management objective and strategy for undertaking the hedge. As of March 31, 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 March 31, 2013, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at March 31, 2013 was 1.37 percent. The Company's interest rate exposure as of March 31, 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) Our chief executive officer and chief financial officer of Energen Corporation have concluded that 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 are effective at that reasonable assurance level.

(b) Our chief executive officer and chief financial officer of Alabama Gas Corporation have concluded that 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.

39

PART II: OTHER INFORMATION

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**
January 1, 2013 through January 31, 2013	—		$	—	—	8,992,700
February 1, 2013 through February 28, 2013	—		—		—	8,992,700
March 1, 2013 through March 31, 2013	1,556	*	45.56		—	8,992,700
Total	1,556		$	45.56	—	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 March 31, 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
May 9, 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
May 9, 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
May 9, 2013	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
May 9, 2013	By	/s/ William D. Marshall
		William D. Marshall
		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.

May 9, 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.

May 9, 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.

May 9, 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.

May 9, 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 March 31, 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 May 9, 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 March 31, 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 May 9, 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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Derivative Commodity Instruments - Offsetting Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivative assets
Gross Amounts Recognized	$ 79,728	$ 149,504
Gross Amounts Offset in the Balance Sheets	(42,839)	(44,135)
Net Amount Presented in the Balance Sheets	36,889	105,369
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Amount	36,889	105,369
Derivative assets
Gross Amounts Recognized	83,987	56,328
Gross Amounts Offset in the Balance Sheets	(42,839)	(44,135)
Net Amount Presented in the Balance Sheets	41,148	12,193
Financial Instruments	0	0
Cash Collateral Received	0	0
Net Amount	$ 41,148	$ 12,193

XML

Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 24,135	$ 45,515
Regulatory assets, noncurrent	109,002	110,566
Regulatory Liability, Current	41,886	45,116
Regulatory Liability, Noncurrent	68,812	80,404
Alabama Gas Corporation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	24,135	45,515
Regulatory assets, noncurrent	109,002	110,566
Regulatory Liability, Current	41,886	45,116
Regulatory Liability, Noncurrent	68,812	80,404
Alabama Gas Corporation | RSE adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	2,262	1,740
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Unbilled service margin
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	22,108	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	1,487	1,237
Alabama Gas Corporation | Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	17,483	18,265
Regulatory Liability, Noncurrent	41,352	53,467
Alabama Gas Corporation | Accretion and depreciation for asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	25,211	24,930
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	33	33
Regulatory Liability, Noncurrent	762	770
Alabama Gas Corporation | Pension and postretirement assets
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	253	170
Regulatory assets, noncurrent	89,316	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	16,884	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	2,802	3,322
Alabama Gas Corporation | Gas supply adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	23,857	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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Commitments and Contingencies - New Mexico Audits (Details) (USD $)	3 Months Ended
	Mar. 31, 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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Derivative Commodity Instruments - Commodity Contracts by Business Segment (Details) (USD $)	Mar. 31, 2013 bbl counterparty		Dec. 31, 2012
Derivative [Line Items]
Number of active counterparties with whom company holds net loss positions	6
Number of large counterparties with whom company holds net loss positions	2
Derivative liabilities	$ 41,148,000		$ 12,193,000
Number of active counterparties with whom company holds net gain positions	7
Number of large counterparties with whom company holds net gain positions	2
Derivative assets	36,889,000		105,369,000
Barrels dedesignated at March 31, 2013	5,078,000
Gross Amounts Recognized	79,728,000		149,504,000
Derivative liability	(83,987,000)		(56,328,000)
Total derivatives	(4,259,000)		93,176,000
Deferred tax assets (liabilities), net	(5,400,000)		(28,400,000)
Oil and gas operations
Derivative [Line Items]
Total derivatives	(4,259,000)		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	77,198,000		125,468,000
Total derivative liabilities	(62,097,000)		(52,862,000)
Total derivatives	15,101,000		72,606,000
Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Gross Amounts Recognized	77,198,000		125,468,000
Total derivative liabilities	(62,097,000)		(52,862,000)
Total derivatives	15,101,000		72,606,000
Designated as Hedging Instrument | Natural gas distribution
Derivative [Line Items]
Gross Amounts Recognized	0		0
Total derivative liabilities	0		0
Total derivatives	0		0
Not Designated as Hedging Instrument
Derivative [Line Items]
Gross Amounts Recognized	2,530,000		24,037,000
Derivative liability	(21,890,000)		(3,467,000)
Total derivatives	(19,360,000)		20,570,000
Not Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Gross Amounts Recognized	2,530,000		24,037,000
Derivative liability	(21,890,000)		(874,000)
Total derivatives	(19,360,000)		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	0		(2,593,000)
Accounts receivable | Designated as Hedging Instrument
Derivative [Line Items]
Gross Amounts Recognized	51,277,000		87,514,000
Derivative liability	(36,245,000)		(37,326,000)
Accounts receivable | Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Gross Amounts Recognized	51,277,000		87,514,000
Derivative liability	(36,245,000)	[1]	(37,326,000)	[1]
Accounts receivable | Designated as Hedging Instrument | Natural gas distribution
Derivative [Line Items]
Gross Amounts Recognized	0		0
Derivative liability	0		0
Accounts receivable | Not Designated as Hedging Instrument
Derivative [Line Items]
Gross Amounts Recognized	(4,342,000)		14,604,000
Accounts receivable | Not Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Gross Amounts Recognized	(4,342,000)	[1]	14,604,000	[1]
Accounts receivable | Not Designated as Hedging Instrument | Natural gas distribution
Derivative [Line Items]
Gross Amounts Recognized	0		0
Long-term asset derivative instruments | Designated as Hedging Instrument
Derivative [Line Items]
Gross Amounts Recognized	25,921,000		37,954,000
Derivative liability	(6,594,000)		(6,810,000)
Long-term asset derivative instruments | Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Gross Amounts Recognized	25,921,000		37,954,000
Derivative liability	(6,594,000)	[1]	(6,810,000)	[1]
Long-term asset derivative instruments | Designated as Hedging Instrument | Natural gas distribution
Derivative [Line Items]
Gross Amounts Recognized	0		0
Derivative liability	0		0
Long-term asset derivative instruments | Not Designated as Hedging Instrument
Derivative [Line Items]
Gross Amounts Recognized	6,872,000		9,433,000
Long-term asset derivative instruments | Not Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Gross Amounts Recognized	6,872,000		9,433,000	[1]
Long-term asset derivative instruments | Not Designated as Hedging Instrument | Natural gas distribution
Derivative [Line Items]
Gross Amounts Recognized	0		0
Accounts payable | Designated as Hedging Instrument
Derivative [Line Items]
Derivative liability	(11,983,000)
Accounts payable | Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Derivative liability	(11,983,000)
Accounts payable | Designated as Hedging Instrument | Natural gas distribution
Derivative [Line Items]
Derivative liability	0
Accounts payable | Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative liability	(20,816,000)		(2,593,000)
Accounts payable | Not Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Derivative liability	(20,816,000)		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	(7,275,000)		(8,726,000)
Long-term liability derivative instruments | Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Derivative liability	(7,275,000)		(8,726,000)
Long-term liability derivative instruments | Designated as Hedging Instrument | Natural gas distribution
Derivative [Line Items]
Derivative liability	0		0
Long-term liability derivative instruments | Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative liability	(1,074,000)		(874,000)
Long-term liability derivative instruments | Not Designated as Hedging Instrument | Oil and gas operations
Derivative [Line Items]
Derivative liability	(1,074,000)		(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	10,300,000
Cash Flow Hedging | J Aron and Company
Derivative [Line Items]
Derivative assets	5,300,000
Cash Flow Hedging | Citibank, N.A.
Derivative [Line Items]
Derivative liabilities	5,100,000
Cash Flow Hedging | Morgan Stanley Capital Group, Inc.
Derivative [Line Items]
Derivative liabilities	$ 24,700,000

[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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Segment Information (Tables)

3 Months Ended

Mar. 31, 2013

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three months ended
	March 31,
(in thousands)	2013			2012
Operating revenues
Oil and gas operations	$	254,994		$	223,957
Natural gas distribution	237,685			194,487
Total	$	492,679		$	418,444
Operating income (loss)
Oil and gas operations	$	26,327		$	26,005
Natural gas distribution	79,293			78,560
Eliminations and corporate expenses	(284		)	(395		)
Total	$	105,336		$	104,170
Other income (expense)
Oil and gas operations	$	(11,993	)	$	(10,558	)
Natural gas distribution	(3,130		)	(3,004		)
Eliminations and other	58			56
Total	$	(15,065	)	$	(13,506	)
Income before income taxes	$	90,271		$	90,664

(in thousands)	March 31, 2013		December 31, 2012
Identifiable assets
Oil and gas operations	$	5,100,983	$	4,975,170
Natural gas distribution	1,155,950		1,177,134
Eliminations and other	36,245		23,586
Total	$	6,293,178	$	6,175,890

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Acquisition and Disposition of Properties (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Gas and Oil Acreage [Line Items]
Asset impairment charges	$ 0	$ 21,545,000
Discount rate	10.00%
Expected time period for future natural gas prices curves to shift lower		5 years
Alabama Gas Corporation | Birmingham Metro Operations Center
Gas and Oil Acreage [Line Items]
Property acreage	11.7
Real Estate, Sales Price	$ 14,000,000
Lease back period after sale	18 months

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013 segment	Mar. 31, 2012	Dec. 31, 2012
Segment Reporting Information
Number of business segments	2
Segment Reporting Information, Profit (Loss)
Operating revenues	$ 492,679	$ 418,444
Operating income (loss)	105,336	104,170
Other income (expense)	(15,065)	(13,506)
Income Before Income Taxes	90,271	90,664
Identifiable assets	6,293,178		6,175,890
Oil and gas operations
Segment Reporting Information, Profit (Loss)
Operating revenues	254,994	223,957
Operating income (loss)	26,327	26,005
Other income (expense)	(11,993)	(10,558)
Identifiable assets	5,100,983		4,975,170
Natural gas distribution
Segment Reporting Information, Profit (Loss)
Operating revenues	237,685	194,487
Operating income (loss)	79,293	78,560
Other income (expense)	(3,130)	(3,004)
Identifiable assets	1,155,950		1,177,134
Eliminations and corporate expenses
Segment Reporting Information, Profit (Loss)
Operating income (loss)	(284)	(395)
Other income (expense)	58	56
Identifiable assets	$ 36,245		$ 23,586

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Derivative Commodity Instruments - Derivative Instruments Change in Fair Value (Details) (Derivative Commodity Instruments, USD $)	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Derivative Commodity Instruments
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at beginning of period	$ 89,019,000		$ 65,801,000
Realized gains	27,107,000		13,181,000
Unrealized gains (losses) relating to instruments held at the reporting date	(63,482,000)	[1]	39,767,000	[1]
Settlements during period	(26,185,000)		(13,826,000)
Balance at end of period	26,459,000		104,923,000
Mark-to-market loss included in earnings, unrealized	12,400,000
Mark-to-market gain included in earnings, unrealized			$ 3,800,000

[1] Includes $12.4 million in mark-to-market losses and $3.8 million in mark-to-market gains for the three months ended March 31, 2013 and 2012.

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Reclassifications of Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended
	Mar. 31, 2013		Mar. 31, 2012
Gains and (losses) on cash flow hedges:
Operating revenues	$ 492,679,000		$ 418,444,000
Interest expense	(16,754,000)		(15,425,000)
Income tax expense	(33,579,000)		(33,258,000)
Pension and postretirement plans:
Settlement charges	500,000
Settlement charges expensed	100,000
Alabama Gas Corporation
Gains and (losses) on cash flow hedges:
Interest expense	(4,030,000)		(4,062,000)
Pension and postretirement plans:
Settlements recognized as a pension asset	400,000
Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Net of tax	8,646,000
Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Total	16,881,000
Income tax expense	(6,427,000)
Net of tax	10,454,000
Pension and Postretirement Plans | Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Total	(2,781,000)
Income tax expense	973,000
Net of tax	(1,808,000)
Pension and postretirement plans:
Transition obligation	(74,000)
Prior service cost	(78,000)
Actuarial losses	(2,254,000)	[1]
Actuarial losses on settlement charges	(375,000)	[1]
Commodity contracts | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Operating revenues	17,290,000
Interest rate swap | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Interest expense	$ (409,000)

[1] In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the 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															3 Months Ended
	Mar. 31, 2013	Mar. 31, 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	Mar. 31, 2013 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Dec. 31, 2012 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Mar. 31, 2013 Alabama Gas Corporation	Dec. 31, 2012 Alabama Gas Corporation	Mar. 31, 2013 Alabama Gas Corporation Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Dec. 31, 2012 Alabama Gas Corporation Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Mar. 31, 2013 Alabama Gas Corporation Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Dec. 31, 2012 Alabama Gas Corporation Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Dec. 31, 2011 Senior Loans Swap	Dec. 31, 2011 Senior Loans Swap Senior Term Loans, Due March 31, 2014 to November 29, 2016	Mar. 31, 2013 Senior Loans Level 1 Swap	Dec. 31, 2012 Senior Loans Level 1 Swap	Mar. 31, 2013 Maximum Alabama Gas Corporation
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt fair value		$ 1,216,900,000	$ 1,255,800,000	$ 1,154,000,000	$ 1,154,000,000			$ 271,300,000	$ 284,700,000	$ 250,000,000	$ 250,000,000
Face amount													200,000,000
Interest rate												2.4175%
Interest rate cash flow hedge liability at fair value														2,900,000	3,300,000
Financing receivable						10,400,000	10,700,000
Financing receivable recorded investment average balance 0 to 60 days past due						3,000
Average finance receivable term																60 months
Time after which delinquent accounts are evaluated	90 days
Time period after which accounts are written off	12 months
Financing receivable recorded investment, equal to greater than 90 days past due						600,000	500,000
Financing Receivable, Allowance for Credit Losses [Roll Forward]
Allowance for credit losses as of December 31, 2012	470,000
Provision	116,000
Allowance for credit losses as of March 31, 2013	$ 586,000

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Regulatory Matters

3 Months Ended

Mar. 31, 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. RSE’s current extension is for a seven-year period through December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology.

Alagasco's allowed range of return on average common equity is 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months ended March 31, 2013, Alagasco had a net $2.4 million pre-tax 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 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) 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, 2012 and 2011.

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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Stock Compensation (Details) (USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended	3 Months Ended
	Jan. 31, 2013	Mar. 31, 2013
Stock options
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period		3 years
Expiration period		10 years
Grants in period, options		134,076
Grants in period, options, fair value		16.66
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period		3 years
Grants in period (in shares)	46,121
Grants in period, fair value (in dollars per share)	$ 48.36
Performance Shares | 2 year vesting period
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period		2 years
Grants in period (in shares)		84,311
Grants in period, fair value (in dollars per share)		59.19
Performance Shares | 3 year vesting period
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period		3 years
Grants in period (in shares)		80,395
Grants in period, fair value (in dollars per share)		60.81
Stock Appreciation Rights (SARs)
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period		3 years
Grants in period (in shares)		88,000
Grants in period, fair value (in dollars per share)		20.05
Restricted Stock Units (RSUs) | Petrotech Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award
Grants in period (in shares)		33,796
Grants in period, fair value (in dollars per share)		50.45
Restricted Stock Units (RSUs) | Petrotech Incentive Plan | 3 year vesting period
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period		3 years
Grants in period (in shares)		52,768
Grants in period, fair value (in dollars per share)		70.39
Deferred Compensation
Share-based Compensation Arrangement by Share-based Payment Award
Noncash payments for repurchase of common stock		71

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

During the three months ended March 31, 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	901
Liabilities settled	(322		)
Accretion expense	1,997
Balance as of March 31, 2013	$	120,599

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

3 Months Ended

Mar. 31, 2013

Alabama Gas Corporation

Regulatory Assets and Liabilities [Line Items]

Schedule of Regulatory Assets and Liabilities

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

(in thousands)	March 31, 2013				December 31, 2012
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	253	$	89,316	$	170	$	90,708
Accretion and depreciation for asset retirement obligation	—		16,884		—		16,536
Risk management activities	—		—		2,593		—
Rate recovery of asset removal costs, net	—		2,802		—		3,322
Gas supply adjustment	23,857		—		42,726		—
Other	25		—		26		—
Total regulatory assets	$	24,135	$	109,002	$	45,515	$	110,566
Regulatory liabilities:
RSE adjustment	$	2,262	$	—	$	1,740	$	—
Unbilled service margin	22,108		—		25,078		—
Postretirement liabilities	—		1,487		—		1,237
Refundable negative salvage	17,483		41,352		18,265		53,467
Asset retirement obligation	—		25,211		—		24,930
Other	33		762		33		770
Total regulatory liabilities	$	41,886	$	68,812	$	45,116	$	80,404

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Employee Benefit Plans (Details) (USD $)	1 Months Ended	3 Months Ended
	Jan. 31, 2013	Mar. 31, 2013	Mar. 31, 2012
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:
Settlement charges		$ 500,000
Settlement charges expensed		100,000
Pension Plans
Components of net periodic benefit cost:
Service cost		3,602,000	2,632,000
Interest cost		2,718,000	2,700,000
Expected long-term return on assets		(3,713,000)	(3,563,000)
Actuarial loss		3,690,000	2,099,000
Prior service cost amortization		122,000	129,000
Settlement charge		144,000	0
Net periodic expense		6,563,000	3,997,000
Estimated required future employer contributions in current fiscal year		0
Contributions by employer in current fiscal year	9,000,000
Estimated discretionary future employer contributions in current fiscal year		0
Benefit payments made in current fiscal year		900,000
Estimated future benefit payments in current fiscal year		2,900,000
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost		444,000	463,000
Interest cost		869,000	1,062,000
Expected long-term return on assets		(1,242,000)	(1,109,000)
Actuarial loss		0	9,000
Transition amortization		324,000	479,000
Net periodic expense		395,000	904,000
Contributions by employer in current fiscal year		500,000
Estimated future employer contributions in current fiscal year		1,100,000
Alabama Gas Corporation
Components of net periodic benefit cost:
Settlements recognized as a pension asset		$ 400,000

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Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2013

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

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

(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
Other comprehensive income (loss) before reclassifications	(26,818		)	—			(26,818		)
Amounts reclassified from accumulated other comprehensive income (loss)	(10,454		)	1,808			(8,646		)
Change in accumulated other comprehensive income (loss)	(37,272		)	1,808			(35,464		)
Balance as of March 31, 2013	$	6,924		$	(50,699	)	$	(43,775	)

Reclassification out of Accumulated Other Comprehensive Income

	Three months ended
	March 31, 2013
(in thousands)	Amounts Reclassified			Line Item Where Presented
Gains and (losses) on cash flow hedges:
Commodity contracts	$	17,290		Operating revenues
Interest rate swap	(409		)	Interest expense
Total cash flow hedges	16,881
Income tax expense	(6,427		)
Net of tax	10,454
Pension and postretirement plans:
Transition obligation	(74		)	Operations and maintenance
Prior service cost	(78		)	Operations and maintenance
Actuarial losses*	(2,254		)	Operations and maintenance
Actuarial losses on settlement charges*	(375		)	Regulatory asset
Total pension and postretirment plans	(2,781		)
Income tax expense	973
Net of tax	(1,808		)
Total reclassifications for the period	$	8,646

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Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Schedule of Quantifying Prior Year Misstatement Not Corrected Due to Materiality [Line Items]
Decrease in operating cash flow due to uncorrected error due to materiality	$ 3.9
Alabama Gas Corporation
Schedule of Quantifying Prior Year Misstatement Not Corrected Due to Materiality [Line Items]
Decrease in operating cash flow due to uncorrected error due to materiality	$ 4.5

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Basis of Presentation

3 Months Ended

Mar. 31, 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.

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 quarter ended March 31, 2012 resulted in a decrease of $3.9 million and $4.5 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 caused no impact to Energen or Alagasco's statements of income.

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Regulatory Matters (Details) (Alabama Gas Corporation, USD $)	0 Months Ended		3 Months Ended
	Dec. 01, 2012	Dec. 01, 2011	Mar. 31, 2013
Regulatory Matters [Line Items]
Enhanced Stability Reserve extension period			7 years
Revenue impact of rate adjustments	$ 7,800,000	$ 13,000,000	$ (2,400,000)
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
Enhanced Stability Reserve refund period			9 years
Enhanced Stability Reserve amortization period			5 years
Enhanced Stability Reserve, amortization expense			660,000
Minimum
Regulatory Matters [Line Items]
Allowed return on average common equity			13.15%
Maximum
Regulatory Matters [Line Items]
Allowed return on average common equity			13.65%
Rate increases as percentage of prior year revenues			4.00%
Limitation on return on equity as percentage of total capitalization			55.00%
APSC Approved Expension of ESR, November 1, 2010
Regulatory Matters [Line Items]
Large commercial and industrial customer budget minimum amount charged to Enhanced Stability Reserve			350,000
APSC Approved Expension of ESR, November 1, 2010 | Force Majeure Event Costs
Regulatory Matters [Line Items]
Extraordinary operating and maintenance expenses minimum amount charged to Enhanced Stability Reserve			275,000
APSC Approved Expension of ESR, November 1, 2010 | Force Majeure Events Costs
Regulatory Matters [Line Items]
Extraordinary operating and maintenance expenses minimum amount charged to Enhanced Stability Reserve			412,500
APSC Approved Expension of ESR, November 1, 2010 | Environmental Response and Self Insurance Costs
Regulatory Matters [Line Items]
Extraordinary operating and maintenance expenses minimum amount charged to Enhanced Stability Reserve			$ 1,000,000

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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
	Mar. 31, 2013	Mar. 31, 2012
Earnings Per Share Reconciliation
Net Income, Basic EPS	$ 56,692	$ 57,406
Basic Shares Oustanding (in shares)	72,143	72,102
Earnings Per Share, Basic (in dollars per share)	$ 0.79	$ 0.80
Effect of dilutive securities
Net Income, Diluted EPS	$ 56,692	$ 57,406
Diluted Shares Outstanding (in shares)	72,288	72,326
Earnings Per Share, Diluted (dollars per share)	$ 0.78	$ 0.79
Stock options
Effect of dilutive securities
Incremental common shares attributable to share-based payment arrangements	144	216
Non-vested restricted stock
Effect of dilutive securities
Incremental common shares attributable to share-based payment arrangements	1	8

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Consolidated Condensed Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating Revenues
Oil and gas operations	$ 254,994	$ 223,957
Natural gas distribution	237,685	194,487
Total operating revenues	492,679	418,444
Operating Expenses
Cost of gas	95,442	59,586
Operations and maintenance	145,837	110,561
Depreciation, depletion and amortization	115,295	94,534
Income taxes
Deferred	29,028	23,182
Asset impairment	0	21,545
Taxes, other than income taxes	28,772	26,235
Accretion expense	1,997	1,813
Total operating expenses	387,343	314,274
Operating Income	105,336	104,170
Other Income (Expense)
Interest expense	(16,754)	(15,425)
Other income	1,758	2,032
Other expense	(69)	(113)
Total other expense	(15,065)	(13,506)
Interest Expense
Income Before Income Taxes	90,271	90,664
Income tax expense	33,579	33,258
Net Income	56,692	57,406
Diluted Earnings Per Average Common Share (in dollars per share)	$ 0.78	$ 0.79
Basic Earnings Per Average Common Share (in dollars per share)	$ 0.79	$ 0.80
Dividends Per Common Share (in dollars per share)	$ 0.145	$ 0.14
Diluted Average Common Shares Outstanding	72,288	72,326
Basic Average Common Shares Outstanding	72,143	72,102
Alabama Gas Corporation
Operating Revenues
Natural gas distribution	237,685	194,487
Operating Expenses
Cost of gas	95,442	59,586
Operations and maintenance	38,017	34,066
Depreciation, depletion and amortization	10,729	10,446
Income taxes
Current	25,921	25,440
Deferred	3,020	3,198
Taxes, other than income taxes	14,204	11,829
Total operating expenses	187,333	144,565
Operating Income	50,352	49,922
Other Income (Expense)
Interest expense	(4,030)	(4,062)
Allowance for funds used during construction	219	134
Other income	750	986
Other expense	(69)	(62)
Total other expense	900	1,058
Interest Expense
Interest on long-term debt	3,378	3,424
Other interest expense	652	638
Net Income	$ 47,222	$ 46,918

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Commitments and Contingencies - Commitments and Agreements (Details) (USD $) In Millions, unless otherwise specified	2 Months Ended	12 Months Ended					3 Months Ended
	Jan. 15, 2012 agreement	Dec. 31, 2012 Cadenhead Well MBoe	Mar. 31, 2013 Cadenhead Well MBoe	Mar. 31, 2013 Contract Termination	Mar. 31, 2013 Alabama Gas Corporation site	Mar. 31, 2013 Crude Oil and Natural Gas MBoe	Mar. 31, 2013 Natural Gas, Delivery and Storage Alabama Gas Corporation	Mar. 31, 2012 Natural Gas, Delivery and Storage Alabama Gas Corporation	Mar. 31, 2013 Natural Gas Alabama Gas Corporation Mcf	Mar. 31, 2013 Wholly Owned Properties Alabama Gas Corporation site
Long-term Purchase Commitment [Line Items]
Remaining contractual volume						29,600
Number of agreements to secure drilling rigs	3
Maximum loss contingency range of possible loss				$ 19
Long-term purchase commitment							94
Long-term purchase commitment, time period							September 2024		August 2020
Long-term commitments expense recognized in statement of operations							14.4	14.3
Long-term purchase commitment minimum quantity required									158,000,000
Recorded unconditional purchase obligation, time period									January 2014
Recorded unconditional purchase obligation									1.1
Recorded unconditional purchase obligation, market value									$ 1.2
Working interest			50.00%
Production (BOE)		63
Expected production (BOE)			34
Chain of title, manufactured gas plant sites					9					4
Chain of title, manufactured gas distribution sites					5					1

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Consolidated Condensed Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Current Assets
Allowance for doubtful accounts	$ 5,446	$ 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	73,083,108	75,067,760
Treasury stock, shares	2,969,784	2,998,620
Alabama Gas Corporation
Current Assets
Allowance for doubtful accounts	$ 4,600	$ 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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Derivative Commodity Instruments - Hedging Transactions (Details) (Cash Flow Hedging)	Mar. 31, 2013 Mcf
Natural Gas | 2013 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	9,400,000
Average Contract Price, per Mcf	4.83
Natural Gas | 2013 | Basin Specific Swaps - San Juan
Derivative [Line Items]
Total Hedged Volumes	24,400,000
Average Contract Price, per Mcf	4.56
Natural Gas | 2013 | Basin Specific Swaps - Permian
Derivative [Line Items]
Total Hedged Volumes	3,400,000
Average Contract Price, per Mcf	3.45
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	25,700,000
Average Contract Price, per Mcf	4.72
Natural Gas | 2014 | Basin Specific Swaps - Permian
Derivative [Line Items]
Total Hedged Volumes	9,700,000
Average Contract Price, per Mcf	3.81
Crude Oil | 2013 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	6,752,000
Average Contract Price, per Bbl	90.99
Crude Oil | 2013 | WTS/WTI Basis Swaps
Derivative [Line Items]
Total Hedged Volumes	2,701,000	[1]
Average Contract Price, per Bbl	(3.02)	[1]
Crude Oil | 2013 | WTI/WTI Basis Swaps
Derivative [Line Items]
Total Hedged Volumes	2,995,000	[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	720,000
Average Contract Price, per Bbl	90.10
Natural Gas Liquids | 2013 | Liquids Swaps
Derivative [Line Items]
Total Hedged Volumes	33,900,000
Average Contract Price, Per Gal	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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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 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, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments 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. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net loss position with six of its active counterparties at March 31, 2013. The two largest counterparty net loss positions at March 31, 2013, Morgan Stanley Capital Group, Inc and Barclays Bank PLC, constituted approximately $24.7 million and $5.1 million, respectively, of Energen Resources’ total net loss on fair value of derivatives. Energen Resources was in a net gain position with seven of its active counterparties at March 31, 2013. The two largest counterparty net gain positions at March 31, 2013, Macquarie Bank Limited and BP Corporation North America Inc., constituted approximately $10.3 million and $5.3 million, respectively, of Energen Resources’ net gain on fair value of derivatives.

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 March 31, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change. Effective March 31, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) of various Permian Basin NYMEX oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to March 31, 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.

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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Derivative Commodity Instruments - Derivatives Measured at Fair Value on a Recurring Basis (Details) (USD $)								3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Dec. 31, 2012 Fair Value, Measurements, Recurring	Mar. 31, 2013 Level 2 Fair Value, Measurements, Recurring		Dec. 31, 2012 Level 2 Fair Value, Measurements, Recurring		Mar. 31, 2013 Level 3	Mar. 31, 2013 Level 3 Fair Value, Measurements, Recurring		Dec. 31, 2012 Level 3 Fair Value, Measurements, Recurring		Mar. 31, 2013 Total Fair Value, Measurements, Recurring	Mar. 31, 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			$ 64,792,000	$ (12,452,000)	[1]	$ (3,629,000)			$ 23,142,000	[1]	$ 68,421,000		$ 10,690,000
Noncurrent assets	26,199,000	40,577,000	40,577,000	12,194,000	[1]	18,899,000			14,005,000	[1]	21,678,000		26,199,000
Current liabilities			(2,593,000)	(24,834,000)	[1]	(2,593,000)			(7,965,000)	[1]	0		(32,799,000)	0	(2,600,000)	0
Noncurrent liabilities	(9,705,000)	(11,305,000)	(9,600,000)	(5,626,000)	[1]	(8,520,000)			(2,723,000)	[1]	(1,080,000)		(8,349,000)
Net derivative asset (liability)			93,176,000	(30,718,000)	[1]	4,157,000	[1]		26,459,000	[1]	89,019,000	[1]	(4,259,000)
Impact on fair value of a 10 percent increase or decrease in commodity prices								28,000,000
Impact on results of operations of a 10 percent increase or decrease in commodity prices								$ 5,200,000

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

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation

	Three months ended					Three months ended
(in thousands, except per share amounts)	March 31, 2013					March 31, 2012
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	56,692	72,143	$	0.79	$	57,406	72,102	$	0.80
Effect of dilutive securities
Stock options			144					216
Non-vested restricted stock			1					8
Diluted EPS	$	56,692	72,288	$	0.78	$	57,406	72,326	$	0.79

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Consolidated Condensed Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Operating Activities
Net Income	$ 56,692	$ 57,406
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	115,295	94,534
Asset impairment	0	21,545
Accretion expense	1,997	1,813
Deferred income taxes	29,028	23,182
Bad debt expense (recovery)	218	(258)
Exploratory expense	541	1,076
Change in derivative fair value	37,977	47,221
(Gain) loss on sale of assets	(656)	47
Other, net	11,078	4,261
Net change in:
Accounts receivable	(35,312)	20,063
Inventories	26,338	1,473
Accounts payable	9,670	7,327
Amounts due customers, including gas supply pass-through	10,254	(31,926)
Income tax receivable	4,781	5,852
Pension and other postretirement benefit contributions	(10,334)	(3,176)
Other current assets and liabilities	3,886	(19,460)
Net cash provided by operating activities	261,453	230,980
Investing Activities
Additions to property, plant and equipment	(297,301)	(276,791)
Acquisitions, net of cash acquired	(13,146)	(68,176)
Proceeds from sale of assets	1,370	13,766
Other, net	(362)	(375)
Net cash used in investing activities	(309,439)	(331,576)
Financing Activities
Payment of dividends on common stock	(10,473)	(10,095)
Issuance of common stock	0	604
Payment of long-term debt	(10)	(25)
Net change in short-term debt	69,000	150,000
Tax benefit on stock compensation	68	227
Other	0	(38)
Net cash provided by financing activities	58,585	140,673
Net change in cash and cash equivalents	10,599	40,077
Cash and cash equivalents at beginning of period	9,704	9,541
Cash and Cash Equivalents at End of Period	20,303	49,618
Alabama Gas Corporation
Operating Activities
Net Income	47,222	46,918
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	10,729	10,446
Deferred income taxes	3,020	3,198
Bad debt expense (recovery)	217	(258)
Other, net	3,685	(2,564)
Net change in:
Accounts receivable	(23,409)	14,706
Inventories	23,317	5,985
Accounts payable	(11,306)	(20,364)
Amounts due customers, including gas supply pass-through	10,254	(31,926)
Income tax receivable	2,762	8,374
Pension and other postretirement benefit contributions	(5,365)	(681)
Other current assets and liabilities	24,183	11,425
Net cash provided by operating activities	85,309	45,259
Investing Activities
Additions to property, plant and equipment	(19,046)	(14,245)
Other, net	886	(767)
Net cash used in investing activities	(18,160)	(15,012)
Financing Activities
Payment of dividends on common stock	(8,438)	(8,027)
Payment of long-term debt	(10)	(25)
Net change in short-term debt	(47,000)	10,000
Other	0	(38)
Net cash provided by financing activities	(55,448)	1,910
Net change in cash and cash equivalents	11,701	32,157
Cash and cash equivalents at beginning of period	5,559	7,817
Cash and Cash Equivalents at End of Period	$ 17,260	$ 39,974

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Consolidated Condensed Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Net Income	$ 56,692	$ 57,406
Other comprehensive income (loss):
Total cash flow hedges	(37,272)	(11,979)
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $26 and $25	48	47
Amortization of prior service cost, net of taxes of $27 and $30	51	55
Amortization of net loss, including settlement charges, net of taxes of $920 and $412	1,709	766
Total pension and postretirement plans	1,808	868
Comprehensive Income	21,228	46,295
Commodity contracts
Other comprehensive income (loss):
Reclassification adjustment for commodity derivative instruments, net of tax	(10,720)	493
Current period change in fair value of interest rate swap, net of tax of ($11) and ($265)	(26,798)	(12,234)
Interest rate swap
Other comprehensive income (loss):
Reclassification adjustment for commodity derivative instruments, net of tax	266	254
Current period change in fair value of interest rate swap, net of tax of ($11) and ($265)	$ (20)	$ (492)

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Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2013

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	March 31, 2013				December 31, 2012
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	253	$	89,316	$	170	$	90,708
Accretion and depreciation for asset retirement obligation	—		16,884		—		16,536
Risk management activities	—		—		2,593		—
Rate recovery of asset removal costs, net	—		2,802		—		3,322
Gas supply adjustment	23,857		—		42,726		—
Other	25		—		26		—
Total regulatory assets	$	24,135	$	109,002	$	45,515	$	110,566
Regulatory liabilities:
RSE adjustment	$	2,262	$	—	$	1,740	$	—
Unbilled service margin	22,108		—		25,078		—
Postretirement liabilities	—		1,487		—		1,237
Refundable negative salvage	17,483		41,352		18,265		53,467
Asset retirement obligation	—		25,211		—		24,930
Other	33		762		33		770
Total regulatory liabilities	$	41,886	$	68,812	$	45,116	$	80,404

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Document and Entity Information	3 Months Ended
	Mar. 31, 2013	May 01, 2013
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Entity Registrant Name	ENERGEN CORP
Entity Central Index Key	0000277595
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		72,222,501
Alabama Gas Corporation
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Entity Registrant Name	ALABAMA GAS CORP
Entity Central Index Key	0000003146
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,972,052

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the 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 three months ended March 31, 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	901
Liabilities settled	(322		)
Accretion expense	1,997
Balance as of March 31, 2013	$	120,599

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 $25.2 million and $24.9 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of March 31, 2013 and December 31, 2012, respectively. Regulatory assets for accumulated asset removal costs of $2.8 million and $3.3 million as of March 31, 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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Consolidated Condensed Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Current period change in fair value of commodity derivative instruments, tax	$ (16,424)	$ (7,498)
Amortization of net obligation at transition, tax	26	25
Amortization of prior service cost, tax	27	30
Current period change in fair value of pension and postretirement plans, tax	920	412
Commodity contracts
Reclassification adjustment for derivative instruments, tax	(6,570)	302
Current period change in fair value of interest rate swap, tax	(16,424)	(7,498)
Interest rate swap
Reclassification adjustment for derivative instruments, tax	143	137
Current period change in fair value of interest rate swap, tax	$ (11)	$ (265)

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Segment Information

3 Months Ended

Mar. 31, 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
	March 31,
(in thousands)	2013			2012
Operating revenues
Oil and gas operations	$	254,994		$	223,957
Natural gas distribution	237,685			194,487
Total	$	492,679		$	418,444
Operating income (loss)
Oil and gas operations	$	26,327		$	26,005
Natural gas distribution	79,293			78,560
Eliminations and corporate expenses	(284		)	(395		)
Total	$	105,336		$	104,170
Other income (expense)
Oil and gas operations	$	(11,993	)	$	(10,558	)
Natural gas distribution	(3,130		)	(3,004		)
Eliminations and other	58			56
Total	$	(15,065	)	$	(13,506	)
Income before income taxes	$	90,271		$	90,664

(in thousands)	March 31, 2013		December 31, 2012
Identifiable assets
Oil and gas operations	$	5,100,983	$	4,975,170
Natural gas distribution	1,155,950		1,177,134
Eliminations and other	36,245		23,586
Total	$	6,293,178	$	6,175,890

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Reconciliation of Earnings Per Share (EPS)

3 Months Ended

Mar. 31, 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)	March 31, 2013					March 31, 2012
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	56,692	72,143	$	0.79	$	57,406	72,102	$	0.80
Effect of dilutive securities
Stock options			144					216
Non-vested restricted stock			1					8
Diluted EPS	$	56,692	72,288	$	0.78	$	57,406	72,326	$	0.79

For the three months ended March 31, 2013 and 2012 the Company had 988,087 and 849,583 options, respectively, that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months ended March 31, 2013, the Company had 161,249performance share awards that were excluded from the computation of diluted EPS. For the three months ended March 31, 2012, the Company had no performance share awards that were excluded from the computation of diluted EPS. For the three months ended March 31, 2013 and 2012, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

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Derivative Commodity Instruments (Tables)

3 Months Ended

Mar. 31, 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)	March 31, 2013
	Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	51,277			$	—	$	51,277
Long-term asset derivative instruments	25,921				—		25,921
Total derivative assets	77,198				—		77,198
Accounts receivable	(36,245		)	*	—		(36,245		)
Long-term asset derivative instruments	(6,594		)	*	—		(6,594		)
Accounts payable	(11,983		)		—		(11,983		)
Long-term liability derivative instruments	(7,275		)		—		(7,275		)
Total derivative liabilities	(62,097		)		—		(62,097		)
Total derivatives designated	15,101				—		15,101
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(4,342		)	*	—		(4,342		)
Long-term asset derivative instruments	6,872				—		6,872
Total derivative assets	2,530				—		2,530
Accounts payable	(20,816		)		—		(20,816		)
Long-term liability derivative instruments	(1,074		)		—		(1,074		)
Total derivative liabilities	(21,890		)		—		(21,890		)
Total derivatives not designated	(19,360		)		—		(19,360		)
Total derivatives	$	(4,259	)		$	—	$	(4,259	)

(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 March 31, 2013			Three months ended March 31, 2012
Loss recognized in OCI on derivatives (effective portion), net of tax of ($16.4) million and ($7.5) million	—	$	(26,798	)	$	(12,234	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	17,824		$	1,872
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(534	)	$	(2,666	)

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 March 31, 2013			Three months ended March 31, 2012
Loss recognized in income on derivatives	Operating revenues	$	(31,501	)	$	(44,005	)

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	9.4	Bcf	$4.83 Mcf	NYMEX Swaps
	24.4	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	3.4	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Oil
2013	6,752	MBbl	$90.99 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	720	MBbl	$90.10 Bbl	NYMEX Swaps
Oil Basis Differential
2013	2,701	MBbl	$(3.02) Bbl	WTS/WTI Basis Swaps*
	2,995	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	33.9	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:

	March 31, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(12,452	)	$	23,142		$	10,690
Noncurrent assets	12,194			14,005			26,199
Current liabilities	(24,834		)	(7,965		)	(32,799		)
Noncurrent liabilities	(5,626		)	(2,723		)	(8,349		)
Net derivative asset (liability)	$	(30,718	)	$	26,459		$	(4,259	)

	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)	March 31, 2013			March 31, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	27,107			13,181
Unrealized gains (losses) relating to instruments held at the reporting date*	(63,482		)	39,767
Settlements during period	(26,185		)	(13,826		)
Balance at end of period	$	26,459		$	104,923

Schedule of Fair Value Inputs, Derivatives, Quantitative Information

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

(in thousands)	Fair Value as of March 31, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	14,529		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
2014	$	16,066		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
Natural Gas Basis - Permian
2013	$	(1,854	)	Discounted Cash Flow	Forward Basis	($0.12) Mcf
2014	$	(2,731	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf
Oil Basis - WTS/WTI
2013	$	(6,209	)	Discounted Cash Flow	Forward Basis	($0.66) Bbl
Oil Basis - WTI/WTI
2013	$	(2,207	)	Discounted Cash Flow	Forward Basis	($0.18 - $0.28) Bbl
Natural Gas Liquids
2013	$	8,865		Discounted Cash Flow	Forward Price	$0.75 - $0.83 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:

	March 31, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	79,728	$	(42,839	)	$	36,889	$	—	$	—	$	36,889
Derivative liabilities	$	83,987	$	(42,839	)	$	41,148	$	—	$	—	$	41,148

	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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Acquisition and Dispositions of Properties

3 Months Ended

Mar. 31, 2013

Extractive Industries [Abstract]

Acquisition and Dispositions of Properties

ACQUISITION AND DISPOSITION OF PROPERTIES

During the first quarter of 2013, Alagasco entered into a purchase and sale agreement to sell its Birmingham Metro Operations Center which is located on 11.7 acres in downtown Birmingham and has been in service since the 1940's. The sales price is approximately $14 million and the sale is expected to close in August of 2013. Effective upon closing, Alagasco plans to lease the facility from the purchaser for a period of approximately 18 months.

During the first quarter of 2012, Energen Resources recognized a noncash 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. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Under various agreements for third party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 29.6 million barrels of oil equivalent (MMBOE) through November 2021.

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 $19 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 $94 million through September 2024. During the three months ending March 31, 2013 and 2012, Alagasco recognized approximately $14.4 million and $14.3 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 158 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At March 31, 2013, the fixed price purchases under these guarantees had a maximum term outstanding through January 2014 and an aggregate purchase price of $1.1 million with a market value of $1.2 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.

On November 2, 2011, Energen Resources spudded the Cadenhead 25-1 Well (the Cadenhead Well) in Ward County, Texas. During the drilling phase, Chesapeake Exploration, LLC, notified Energen Resources that it believed it was the owner of the lease from which the Cadenhead Well was producing. Shortly thereafter, Energen Resources filed a declaratory judgment action in the District Court of Ward County, Texas to resolve the title dispute. Energen Resources has a fifty percent working interest in the Cadenhead Well. The Cadenhead Well produced approximately 63 net MBOE in 2012 and is expected to produce approximately 34 net MBOE in 2013. On January 18, 2013, a judgment was entered which was adverse to Energen Resources' claim of ownership. The Company believes the adverse ruling was incorrect, and plans to vigorously pursue all available avenues of appeal.

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.

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 May 2012, Alagasco received from the EPA a Request for Information Pursuant to Section 104 of CERCLA relating to the EPA's investigation of a site which it refers to as the 35^th Avenue Superfund Site in and around Birmingham, Jefferson County, Alabama. The inquiry requests information about a parcel owned by Alagasco and located in the vicinity of the 35^th Avenue site. The parcel is the former site of a manufactured gas distribution facility. Alagasco has responded to the inquiry.

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

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company's New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department's findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of March 31, 2013.

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Stock Compensation

3 Months Ended

Mar. 31, 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 provided 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 provided for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provided that payment of earned performance share awards be made in the form of Company common stock. The Company estimated fair value of performance share awards based on the quoted market price of the Company's common stock and adjusted each period for the expected payout ratio. 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.

2004 Stock Appreciation Rights Plan

The Energen 2004 Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 88,000 awards during the first quarter of 2013. These awards had a fair value of $20.05 as of March 31, 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 three months ended March 31, 2013, Energen Resources awarded 33,796 Petrotech units, none of which included a market condition, with a fair value of $50.45 as of March 31, 2013. Also awarded were 52,768 Petrotech units which included a market condition and had a fair value of $70.39 as of March 31, 2013. These awards have a three-year vesting period.

Stock Repurchase Program

During the three months ended March 31, 2013, the Company had noncash purchases of approximately $71,000 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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Employee Benefit Plans

3 Months Ended

Mar. 31, 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 March 31,
(in thousands)	2013			2012
Components of net periodic benefit cost:
Service cost	$	3,602		$	2,632
Interest cost	2,718			2,700
Expected long-term return on assets	(3,713		)	(3,563		)
Actuarial loss	3,690			2,099
Prior service cost amortization	122			129
Settlement charge	144			—
Net periodic expense	$	6,563		$	3,997

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 currently expected to be made to the pension plans by the Company during 2013. For the three months ending March 31, 2013, the Company made benefit payments aggregating $0.9 million to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $2.9 million 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.

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

	Three months ended March 31,
(in thousands)	2013			2012
Components of net periodic benefit cost:
Service cost	$	444		$	463
Interest cost	869			1,062
Expected long-term return on assets	(1,242		)	(1,109		)
Actuarial loss	—			9
Transition amortization	324			479
Net periodic expense	$	395		$	904

For the three months ended March 31, 2013, the Company made contributions aggregating $0.5 million to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $1.1 million to the postretirement benefit plans through the remainder of 2013.

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Financial Instruments

3 Months Ended

Mar. 31, 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, approximates $1,216.9 million and $1,255.8 million and has a carrying value of $1,154.0 million and $1,154.0 million at March 31, 2013 and December 31, 2012, respectively. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $271.3 million and $284.7 million and has a carrying value of $250.0 million and $250.0 million at March 31, 2013 and December 31, 2012, respectively. The fair values were 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 $2.9 million and a $3.3 million liability at March 31, 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 March 31, 2013 and December 31, 2012, Alagasco’s finance receivable totaled $10.4 million and $10.7 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.6 million and $0.5 million as of March 31, 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	116
Allowance for credit losses as of March 31, 2013	$	586

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Derivative Commodity Instruments - Derivative Instruments by Income Statement Location (Details) (USD $)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Loss recognized in OCI on derivatives (effective portion), net of tax of ($16.4) million and ($7.5) million	$ (26,798,000)	$ (12,234,000)
Gain (loss) recognized in OCI (loss) effective portion tax	16,424,000	7,498,000
Gain (loss) reclassification from AOCI to income estimated net amount to be transferred	1,600,000
Fair Value Hedging | Natural Gas | 2013
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount	4,200,000
Fair Value Hedging | Natural Gas | 2014
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount	9,700,000
Fair Value Hedging | Crude Oil | 2013
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount	10,500,000
Fair Value Hedging | Crude Oil | 2014
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount	8,200,000
Fair Value Hedging | Crude Oil | 2015
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount	700,000
Fair Value Hedging | Natural Gas Liquids | 2013
Derivative Instruments, Gain (Loss) [Line Items]
Nonmonetary notional amount	1,600,000
Operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain reclassified from accumulated OCI into income (effective portion)	17,824,000	1,872,000
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	(534,000)	(2,666,000)
Loss recognized in income on derivatives	$ (31,501,000)	$ (44,005,000)

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Rollforward of Accumulated Other Comprehensive Income (Loss) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance as of December 31, 2012	$ (8,311)
Other comprehensive income (loss) before reclassifications	(26,818)
Amounts reclassified from accumulated other comprehensive income (loss)	(8,646)
Change in accumulated other comprehensive income (loss)	(35,464)
Balance as of March 31, 2013	(43,775)
Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance as of December 31, 2012	44,196
Other comprehensive income (loss) before reclassifications	(26,818)
Amounts reclassified from accumulated other comprehensive income (loss)	(10,454)
Change in accumulated other comprehensive income (loss)	(37,272)
Balance as of March 31, 2013	6,924
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	0
Amounts reclassified from accumulated other comprehensive income (loss)	1,808
Change in accumulated other comprehensive income (loss)	1,808
Balance as of March 31, 2013	$ (50,699)

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Recently Issued Accounting Standards

3 Months Ended

Mar. 31, 2013

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2011, the FASB issued Accounting Standard Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities. The amendments in this update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. The amendment is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. In January 2013, the FASB issued 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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Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 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 March 31,
(in thousands)	2013			2012
Components of net periodic benefit cost:
Service cost	$	3,602		$	2,632
Interest cost	2,718			2,700
Expected long-term return on assets	(3,713		)	(3,563		)
Actuarial loss	3,690			2,099
Prior service cost amortization	122			129
Settlement charge	144			—
Net periodic expense	$	6,563		$	3,997

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 March 31,
(in thousands)	2013			2012
Components of net periodic benefit cost:
Service cost	$	444		$	463
Interest cost	869			1,062
Expected long-term return on assets	(1,242		)	(1,109		)
Actuarial loss	—			9
Transition amortization	324			479
Net periodic expense	$	395		$	904

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of December 31, 2012	$ 118,023
Liabilities incurred	901
Liabilities settled	(322)
Accretion expense	1,997	1,813
Balance as of March 31, 2013	120,599
Regulatory assets, noncurrent	109,002		110,566
Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance as of December 31, 2012			24,900
Balance as of March 31, 2013	25,200		24,900
Regulatory assets, noncurrent	109,002		110,566
Asset removal costs | Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory assets, noncurrent	$ 2,802		$ 3,322

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Reconciliation of Earnings Per Share (EPS) - Antidilutive Securities (Details)	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	988,087	849,583
Performance Shares
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	161,249	0

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Consolidated Condensed Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Current Assets
Cash and cash equivalents	$ 20,303	$ 9,704
Accounts receivable
Allowance for doubtful accounts	(5,446)	(6,549)
Accounts receivable, net of allowance for doubtful accounts of $5,446 at March 31, 2013, and $6,549 at December 31, 2012	241,507	277,900
Inventories
Storage gas inventory	9,264	32,205
Materials and supplies	25,283	28,291
Liquified natural gas in storage	3,109	3,498
Regulatory asset	24,135	45,515
Income tax receivable	1,883	6,664
Deferred income taxes	27,278	8,520
Prepayments and other	12,084	12,823
Total current assets	364,846	425,120
Property, Plant and Equipment
Oil and gas properties, successful efforts method	6,712,635	6,439,127
Less accumulated depreciation, depletion and amortization	1,858,960	1,765,241
Oil and gas properties, net	4,853,675	4,673,886
Utility plant	1,435,924	1,416,590
Less accumulated depreciation	583,625	573,947
Utility plant, net	852,299	842,643
Other property, net	25,218	25,107
Total property, plant and equipment, net	5,731,192	5,541,636
Other Assets
Regulatory asset	109,002	110,566
Pension and other postretirement assets	1,732	1,404
Long-term derivative instruments	26,199	40,577
Deferred charges and other	60,207	56,587
Total other assets	197,140	209,134
TOTAL ASSETS	6,293,178	6,175,890
Current Liabilities
Long-term debt due within one year	75,000	50,000
Notes payable to banks	712,000	643,000
Accounts payable	285,920	257,579
Accrued taxes	38,666	30,076
Customers' deposits	25,231	24,705
Amounts due customers	10,580	19,718
Accrued wages and benefits	17,587	24,984
Regulatory liability	41,886	45,116
Royalty payable	38,771	34,426
Other	27,344	30,178
Total current liabilities	1,272,985	1,159,782
Long-term debt	1,078,529	1,103,528
Deferred Credits and Other Liabilities
Asset retirement obligation	120,599	118,023
Pension and other postretirement liabilities	106,515	110,282
Regulatory liability	68,812	80,404
Long-term derivative instruments	9,705	11,305
Deferred income taxes	931,628	905,601
Other	12,981	10,275
Total deferred credits and other liabilities	1,250,240	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	751	751
Premium on capital stock	493,928	492,108
Capital surplus	2,802	2,802
Retained earnings	2,360,274	2,314,055
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	8,834	46,352
Pension and postretirement plans	(50,699)	(52,507)
Interest rate swap	(1,910)	(2,156)
Deferred compensation plan	3,416	2,774
Treasury stock, at cost: 2,969,784 shares at March 31, 2013, and 2,998,620 shares at December 31, 2012	(125,972)	(127,489)
Total shareholders' equity	2,691,424	2,676,690
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	6,293,178	6,175,890
Alabama Gas Corporation
Current Assets
Cash and cash equivalents	17,260	5,559
Accounts receivable
Gas	99,657	94,011
Other	5,698	5,117
Affiliated companies	4,620	5,742
Allowance for doubtful accounts	(4,600)	(5,700)
Inventories
Storage gas inventory	9,264	32,205
Materials and supplies	5,541	5,528
Liquified natural gas in storage	3,109	3,498
Regulatory asset	24,135	45,515
Income tax receivable	0	2,762
Deferred income taxes	18,669	18,799
Prepayments and other	3,674	4,451
Total current assets	187,027	217,487
Property, Plant and Equipment
Utility plant	1,435,924	1,416,590
Less accumulated depreciation	583,625	573,947
Utility plant, net	852,299	842,643
Other property, net	41	42
Other Assets
Regulatory asset	109,002	110,566
Pension and other postretirement assets	1,103	848
Deferred charges and other	11,098	11,290
Total other assets	121,203	122,704
TOTAL ASSETS	1,160,570	1,182,876
Current Liabilities
Notes payable to banks	30,000	77,000
Accounts payable	38,264	51,741
Accrued taxes	47,068	24,186
Customers' deposits	25,231	24,705
Amounts due customers	10,580	19,718
Accrued wages and benefits	6,184	6,703
Regulatory liability	41,886	45,116
Other	9,535	9,018
Total current liabilities	208,748	258,187
Long-term debt	250,018	250,028
Deferred Credits and Other Liabilities
Pension and other postretirement liabilities	39,914	43,611
Regulatory liability	68,812	80,404
Deferred income taxes	192,271	189,381
Other	1,520	762
Total deferred credits and other liabilities	302,517	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	364,783	325,999
Accumulated other comprehensive income (loss), net of tax
Total shareholders' equity	399,287	360,503
Total capitalization	649,305	610,531
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ 1,160,570	$ 1,182,876

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Derivative Commodity Instruments

3 Months Ended

Mar. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Commodity Instruments

DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen's oil and gas subsidiary, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in operating revenues immediately. All derivative transactions are included in operating activities on the consolidated condensed statements of cash flows.

Energen Resources periodically enters into derivative commodity instruments 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. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges typically with investment and commercial banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net loss position with six of its active counterparties at March 31, 2013. The two largest counterparty net loss positions at March 31, 2013, Morgan Stanley Capital Group, Inc and Barclays Bank PLC, constituted approximately $24.7 million and $5.1 million, respectively, of Energen Resources’ total net loss on fair value of derivatives. Energen Resources was in a net gain position with seven of its active counterparties at March 31, 2013. The two largest counterparty net gain positions at March 31, 2013, Macquarie Bank Limited and BP Corporation North America Inc., constituted approximately $10.3 million and $5.3 million, respectively, of Energen Resources’ net gain on fair value of derivatives.

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 March 31, 2013, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge, and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change. Effective March 31, 2013, Energen Resources dedesignated 5,078 thousand barrels (MBbl) of various Permian Basin NYMEX oil contracts due to lack of correlation. Any gains or losses from inception of the hedge to March 31, 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.

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

(in thousands)	March 31, 2013
	Oil and Gas Operations				Natural Gas Distribution		Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	51,277			$	—	$	51,277
Long-term asset derivative instruments	25,921				—		25,921
Total derivative assets	77,198				—		77,198
Accounts receivable	(36,245		)	*	—		(36,245		)
Long-term asset derivative instruments	(6,594		)	*	—		(6,594		)
Accounts payable	(11,983		)		—		(11,983		)
Long-term liability derivative instruments	(7,275		)		—		(7,275		)
Total derivative liabilities	(62,097		)		—		(62,097		)
Total derivatives designated	15,101				—		15,101
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(4,342		)	*	—		(4,342		)
Long-term asset derivative instruments	6,872				—		6,872
Total derivative assets	2,530				—		2,530
Accounts payable	(20,816		)		—		(20,816		)
Long-term liability derivative instruments	(1,074		)		—		(1,074		)
Total derivative liabilities	(21,890		)		—		(21,890		)
Total derivatives not designated	(19,360		)		—		(19,360		)
Total derivatives	$	(4,259	)		$	—	$	(4,259	)

(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 $5.4 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 March 31, 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 March 31, 2013			Three months ended March 31, 2012
Loss recognized in OCI on derivatives (effective portion), net of tax of ($16.4) million and ($7.5) million	—	$	(26,798	)	$	(12,234	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	17,824		$	1,872
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(534	)	$	(2,666	)

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 March 31, 2013			Three months ended March 31, 2012
Loss recognized in income on derivatives	Operating revenues	$	(31,501	)	$	(44,005	)

As of March 31, 2013, $1.6 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. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of March 31, 2013, the Company had 4.2 billion cubic feet (Bcf) and 9.7 Bcf of natural gas hedges which expire during 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 10.5 million barrels (MMBbl), 8.2 MMBbl and 0.7 MMBbl of oil and oil basis hedges which expire during 2013, 2014 and 2015, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2013 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges.

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

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2013	9.4	Bcf	$4.83 Mcf	NYMEX Swaps
	24.4	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	3.4	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	10.6	Bcf	$4.55 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	9.7	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
Oil
2013	6,752	MBbl	$90.99 Bbl	NYMEX Swaps
2014	9,796	MBbl	$92.64 Bbl	NYMEX Swaps
2015	720	MBbl	$90.10 Bbl	NYMEX Swaps
Oil Basis Differential
2013	2,701	MBbl	$(3.02) Bbl	WTS/WTI Basis Swaps*
	2,995	MBbl	$(1.00) Bbl	WTI/WTI Basis Swaps**
Natural Gas Liquids
2013	33.9	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 March 31, 2013, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015. Alagasco has not entered into any cash flow derivative transactions on its gas supply since 2010. 

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

	March 31, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(12,452	)	$	23,142		$	10,690
Noncurrent assets	12,194			14,005			26,199
Current liabilities	(24,834		)	(7,965		)	(32,799		)
Noncurrent liabilities	(5,626		)	(2,723		)	(8,349		)
Net derivative asset (liability)	$	(30,718	)	$	26,459		$	(4,259	)

	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 March 31, 2013, Alagasco had no derivative instruments. As of December 31, 2012, Alagasco had $2.6 million of derivative instruments which are classified as Level 2 fair values and are 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 $28 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $5.2 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)	March 31, 2013			March 31, 2012
Balance at beginning of period	$	89,019		$	65,801
Realized gains	27,107			13,181
Unrealized gains (losses) relating to instruments held at the reporting date*	(63,482		)	39,767
Settlements during period	(26,185		)	(13,826		)
Balance at end of period	$	26,459		$	104,923

*Includes $12.4 million in mark-to-market losses and $3.8 million in mark-to-market gains for the three months ended March 31, 2013 and 2012.

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

(in thousands)	Fair Value as of March 31, 2013			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2013	$	14,529		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
2014	$	16,066		Discounted Cash Flow	Forward Basis	($0.14 - $0.16) Mcf
Natural Gas Basis - Permian
2013	$	(1,854	)	Discounted Cash Flow	Forward Basis	($0.12) Mcf
2014	$	(2,731	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.14) Mcf
Oil Basis - WTS/WTI
2013	$	(6,209	)	Discounted Cash Flow	Forward Basis	($0.66) Bbl
Oil Basis - WTI/WTI
2013	$	(2,207	)	Discounted Cash Flow	Forward Basis	($0.18 - $0.28) Bbl
Natural Gas Liquids
2013	$	8,865		Discounted Cash Flow	Forward Price	$0.75 - $0.83 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:

	March 31, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	79,728	$	(42,839	)	$	36,889	$	—	$	—	$	36,889
Derivative liabilities	$	83,987	$	(42,839	)	$	41,148	$	—	$	—	$	41,148

	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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Financial Instruments (Tables)

3 Months Ended

Mar. 31, 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	116
Allowance for credit losses as of March 31, 2013	$	586

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Derivative Commodity Instruments - Quantitative Disclosures About Fair Value (Details) (USD $) In Thousands, unless otherwise specified				3 Months Ended			3 Months Ended				3 Months Ended				3 Months Ended			3 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2013	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2013 Minimum	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2013 Maximum	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2014	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2014 Minimum	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - San Juan 2014 Maximum	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - Permian 2013	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - Permian 2014	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - Permian 2014 Minimum	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Basis - Permian 2014 Maximum	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Oil Basis - WTS/WTI 2013	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Oil Basis - WTI/WTI 2013	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Oil Basis - WTI/WTI 2013 Minimum	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Oil Basis - WTI/WTI 2013 Maximum	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Liquids 2013	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Liquids 2013 Minimum	Mar. 31, 2013 Income Approach Valuation Technique Level 3 Natural Gas Liquids 2013 Maximum
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of March 31, 2013	$ 36,889	$ 105,369	$ 14,529			$ 16,066											$ 8,865
Fair Value as of March 31, 2013									$ (1,854)	$ (2,731)			$ (6,209)	$ (2,207)
Fair Value Inputs, Price Per Cubic Foot				0.14	0.16		0.14	0.16	0.12		0.12	0.14
Fair Value Inputs, Price Per Barrel													0.66		0.18	0.28
Fair Value Inputs, Price Per Gallon																		0.75	0.83

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Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2013

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2012	$	44,196		$	(52,507	)	$	(8,311	)
Other comprehensive income (loss) before reclassifications	(26,818		)	—			(26,818		)
Amounts reclassified from accumulated other comprehensive income (loss)	(10,454		)	1,808			(8,646		)
Change in accumulated other comprehensive income (loss)	(37,272		)	1,808			(35,464		)
Balance as of March 31, 2013	$	6,924		$	(50,699	)	$	(43,775	)

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

	Three months ended
	March 31, 2013
(in thousands)	Amounts Reclassified			Line Item Where Presented
Gains and (losses) on cash flow hedges:
Commodity contracts	$	17,290		Operating revenues
Interest rate swap	(409		)	Interest expense
Total cash flow hedges	16,881
Income tax expense	(6,427		)
Net of tax	10,454
Pension and postretirement plans:
Transition obligation	(74		)	Operations and maintenance
Prior service cost	(78		)	Operations and maintenance
Actuarial losses*	(2,254		)	Operations and maintenance
Actuarial losses on settlement charges*	(375		)	Regulatory asset
Total pension and postretirment plans	(2,781		)
Income tax expense	973
Net of tax	(1,808		)
Total reclassifications for the period	$	8,646

* In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the 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.