10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 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, 2014

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

Number of shares outstanding of each of the registrant’s classes of common stock as of May 1, 2014.

Energen Corporation	$0.01 par value	72,781,704 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, 2014

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 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
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

ENERGEN CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
(Unaudited)
	Three months ended
	March 31,
(in thousands, except per share data)	2014			2013
Operating Revenues
Oil and gas operations	$	297,278		$	236,331
Natural gas distribution	263,900			237,685
Total operating revenues	561,178			474,016
Operating Expenses
Cost of gas	128,114			95,442
Operations and maintenance	155,072			140,712
Depreciation, depletion and amortization	135,697			105,828
Taxes, other than income taxes	35,853			28,157
Accretion expense	1,843			1,687
Total operating expenses	456,579			371,826
Operating Income	104,599			102,190
Other Income (Expense)
Interest expense	(17,640		)	(16,752		)
Other income	1,384			1,734
Other expense	(54		)	(69		)
Total other expense	(16,310		)	(15,087		)
Income From Continuing Operations Before Income Taxes	88,289			87,103
Income tax expense	32,797			32,409
Income From Continuing Operations	55,492			54,694
Discontinued Operations, net of tax
Income (loss) from discontinued operations	(1,126		)	1,998
Loss on disposal of discontinued operations	(1,050		)	—
Income (Loss) From Discontinued Operations	(2,176		)	1,998
Net Income	$	53,316		$	56,692
Diluted Earnings Per Average Common Share
Continuing operations	$	0.76		$	0.75
Discontinued operations	(0.03		)	0.03
Net Income	$	0.73		$	0.78
Basic Earnings Per Average Common Share
Continuing operations	$	0.76		$	0.76
Discontinued operations	(0.03		)	0.03
Net Income	$	0.73		$	0.79
Dividends Per Common Share	$	0.150		$	0.145
Diluted Average Common Shares Outstanding	73,045			72,288
Basic Average Common Shares Outstanding	72,629			72,143

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

3

ENERGEN CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
	Three months ended
	March 31,
(in thousands)	2014			2013
Net Income	$	53,316		$	56,692
Other comprehensive income (loss):
Cash flow hedges:
Current period change in fair value of derivative commodity instruments, net of tax of $1 and ($16,424), respectively	2			(26,798		)
Reclassification adjustment for derivative commodity instruments, net of tax of ($1,541) and ($6,570), respectively	(2,513		)	(10,720		)
Current period change in fair value of interest rate swap, net of tax of ($62) and ($11), respectively	(115		)	(20		)
Reclassification adjustment for interest rate swap, net of tax of $157 and $143, respectively	289			266
Total cash flow hedges	(2,337		)	(37,272		)
Pension and postretirement plans:
Amortization of net obligation at transition, net of tax of $3 and $26, respectively	6			48
Amortization of prior service cost, net of tax of $26 and $27, respectively	48			51
Amortization of net loss, including settlement charges, net of tax of $2,994 and $920, respectively	5,559			1,709
Total pension and postretirement plans	5,613			1,808
Comprehensive Income	$	56,592		$	21,228

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

4

ENERGEN CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
(in thousands)	March 31, 2014		December 31, 2013
ASSETS
Current Assets
Cash and cash equivalents	$	35,343	$	5,555
Accounts receivable, net of allowance for doubtful accounts of $5,684 and $5,694 at March 31, 2014 and December 31, 2013, respectively	299,118		257,545
Inventories
Storage gas inventory	19,444		32,095
Materials and supplies	16,071		16,601
Liquified natural gas in storage	1,381		3,634
Regulatory assets	1,283		2,756
Income tax receivable	848		5,765
Assets held for sale	1,871		51,104
Deferred income taxes	53,843		41,299
Prepayments and other	9,827		10,877
Total current assets	439,029		427,231
Property, Plant and Equipment
Oil and gas properties, successful efforts method	7,130,801		6,864,375
Less accumulated depreciation, depletion and amortization	1,898,950		1,776,802
Oil and gas properties, net	5,231,851		5,087,573
Utility plant	1,503,696		1,491,433
Less accumulated depreciation	615,519		605,924
Utility plant, net	888,177		885,509
Other property, net	33,690		30,556
Total property, plant and equipment, net	6,153,718		6,003,638
Other Assets
Regulatory assets	82,570		84,890
Other postretirement assets	35,769		35,351
Long-term derivative instruments	2,638		5,439
Deferred charges and other	66,666		65,663
Total other assets	187,643		191,343
TOTAL ASSETS	$	6,780,390	$	6,622,212

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

5

ENERGEN CORPORATION
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
(in thousands, except share and per share data)	March 31, 2014			December 31, 2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	60,000		$	60,000
Notes payable to banks	575,000			539,000
Accounts payable	300,069			250,756
Accrued taxes	55,534			36,228
Customer deposits	21,654			21,692
Amounts due customers	6,397			16,990
Accrued wages and benefits	17,758			33,884
Regulatory liabilities	80,698			49,006
Royalty payable	61,344			51,519
Liabilities related to assets held for sale	3,410			18,545
Other	28,620			32,273
Total current liabilities	1,210,484			1,109,893
Long-term debt	1,328,442			1,343,464
Deferred Credits and Other Liabilities
Asset retirement obligations	110,729			108,533
Pension liabilities	72,465			67,675
Regulatory liabilities	83,240			94,125
Long-term derivative instruments	1,011			398
Deferred income taxes	1,037,898			1,013,245
Other	24,994			26,860
Total deferred credits and other liabilities	1,330,337			1,310,836
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, cumulative, $0.01 par value, 5,000,000 shares authorized	—			—
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized, 75,651,310 shares and 75,574,156 shares issued at March 31, 2014 and December 31, 2013, respectively	757			756
Premium on capital stock	528,632			520,909
Capital surplus	2,802			2,802
Retained earnings	2,519,025			2,476,616
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	10,851			13,362
Pension and postretirement plans	(26,632		)	(32,245		)
Interest rate swap	(1,010		)	(1,184		)
Deferred compensation plan	3,241			3,259
Treasury stock, at cost: 2,965,849 shares and 2,967,999 shares at March 31, 2014 and December 31, 2013, respectively	(126,539		)	(126,256		)
Total shareholders’ equity	2,911,127			2,858,019
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	6,780,390		$	6,622,212

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

6

ENERGEN CORPORATION
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Three months ended March 31,(in thousands)	2014			2013
Operating Activities
Net income	$	53,316		$	56,692
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	137,449			115,295
Accretion expense	2,095			1,997
Deferred income taxes	10,531			29,028
Bad debt expense	461			218
Exploratory expense	1,277			541
Change in derivative fair value	39,555			37,977
(Gain) loss on sale of assets	995			(656		)
Stock-based compensation expense	5,228			3,063
Other, net	15,716			7,839
Net change in:
Accounts receivable	(50,857		)	(35,312		)
Inventories	15,434			26,338
Accounts payable	30,842			9,670
Amounts due customers, including gas supply pass-through	27,098			10,254
Income tax receivable	4,917			4,781
Pension and other postretirement benefit contributions	(3,880		)	(10,334		)
Other current assets and liabilities	6,774			4,062
Net cash provided by operating activities	296,951			261,453
Investing Activities
Additions to property, plant and equipment	(282,334		)	(297,301		)
Acquisitions, net of cash acquired	(6,537		)	(13,146		)
Proceeds from sale of assets	8,019			1,370
Purchase of short-term investments	(84,000		)	—
Sale of short-term investments	84,000			—
Other, net	(122		)	(362		)
Net cash used in investing activities	(280,974		)	(309,439		)
Financing Activities
Payment of dividends on common stock	(10,907		)	(10,473		)
Issuance of common stock	3,060			—
Reduction of long-term debt	(15,028		)	(10		)
Net change in short-term debt	36,000			69,000
Tax benefit on stock compensation	686			68
Net cash provided by financing activities	13,811			58,585
Net change in cash and cash equivalents	29,788			10,599
Cash and cash equivalents at beginning of period	5,555			9,704
Cash and cash equivalents at end of period	$	35,343		$	20,303

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

7

ALABAMA GAS CORPORATION
CONDENSED STATEMENTS OF INCOME
(Unaudited)
	Three months ended
	March 31,
(in thousands)	2014			2013
Operating Revenues	$	263,900		$	237,685
Operating Expenses
Cost of gas	128,114			95,442
Operations and maintenance	36,224			38,017
Depreciation and amortization	11,325			10,729
Income taxes
Current	25,217			25,921
Deferred	1,267			3,020
Taxes, other than income taxes	15,886			14,204
Total operating expenses	218,033			187,333
Operating Income	45,867			50,352
Other Income (Expense)
Allowance for funds used during construction	73			219
Other income	1,508			750
Other expense	(455		)	(69		)
Total other income	1,126			900
Interest Expense
Interest on long-term debt	3,376			3,378
Other interest expense	589			652
Total interest expense	3,965			4,030
Net Income	$	43,028		$	47,222

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

8

ALABAMA GAS CORPORATION
CONDENSED BALANCE SHEETS
(Unaudited)
(in thousands)	March 31, 2014			December 31, 2013
ASSETS
Property, Plant and Equipment
Utility plant	$	1,503,696		$	1,491,433
Less accumulated depreciation	615,519			605,924
Utility plant, net	888,177			885,509
Other property, net	40			41
Current Assets
Cash	34,069			3,032
Accounts receivable
Gas	109,601			103,301
Other	5,104			5,447
Affiliated companies	3,967			4,662
Allowance for doubtful accounts	(5,000		)	(5,000		)
Inventories
Storage gas inventory	19,444			32,095
Materials and supplies	5,188			5,471
Liquified natural gas in storage	1,381			3,634
Regulatory assets	1,283			2,756
Income tax receivable	—			3,644
Deferred income taxes	19,820			20,049
Prepayments and other	3,768			4,654
Total current assets	198,625			183,745
Other Assets
Regulatory assets	82,570			84,890
Other postretirement assets	26,813			26,457
Deferred charges and other	17,117			17,433
Total other assets	126,500			128,780
TOTAL ASSETS	$	1,213,342		$	1,198,075

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

9

ALABAMA GAS CORPORATION
CONDENSED BALANCE SHEETS
(Unaudited)
(in thousands, except share data)	March 31, 2014		December 31, 2013
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, 2014 and December 31, 2013	20		20
Premium on capital stock	31,682		31,682
Capital surplus	2,802		2,802
Retained earnings	382,309		350,076
Total common shareholder’s equity	416,813		384,580
Long-term debt	249,895		249,923
Total capitalization	666,708		634,503
Current Liabilities
Notes payable to banks	—		50,000
Accounts payable	52,938		48,653
Accrued taxes	47,247		28,027
Customer deposits	21,654		21,692
Amounts due customers	6,397		16,990
Accrued wages and benefits	6,343		7,682
Regulatory liabilities	80,698		49,006
Other	10,155		10,113
Total current liabilities	225,432		232,163
Deferred Credits and Other Liabilities
Deferred income taxes	206,669		205,631
Pension liabilities	19,982		20,191
Regulatory liabilities	83,240		94,125
Other	11,311		11,462
Total deferred credits and other liabilities	321,202		331,409
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,213,342	$	1,198,075

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

10

ALABAMA GAS CORPORATION
CONDENSED STATEMENTS OF CASH FLOWS
(Unaudited)
Three months ended March 31,(in thousands)	2014			2013
Operating Activities
Net income	$	43,028		$	47,222
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	11,325			10,729
Deferred income taxes	1,267			3,020
Bad debt expense	466			217
Gain on sale of assets	(612		)	—
Other, net	1,902			3,685
Net change in:
Accounts receivable	(20,830		)	(23,409		)
Inventories	15,187			23,317
Accounts payable	6,242			(11,306		)
Amounts due customers, including gas supply pass-through	27,098			10,254
Income tax receivable	3,644			2,762
Pension and other postretirement benefit contributions	(1,590		)	(5,365		)
Other current assets and liabilities	18,769			24,183
Net cash provided by operating activities	105,896			85,309
Investing Activities
Additions to property, plant and equipment	(15,465		)	(19,046		)
Proceeds from sale of assets	706			—
Other, net	723			886
Net cash used in investing activities	(14,036		)	(18,160		)
Financing Activities
Payment of dividends on common stock	(10,795		)	(8,438		)
Reduction of long-term debt	(28		)	(10		)
Net change in short-term debt	(50,000		)	(47,000		)
Net cash used in financing activities	(60,823		)	(55,448		)
Net change in cash and cash equivalents	31,037			11,701
Cash and cash equivalents at beginning of period	3,032			5,559
Cash and cash equivalents at end of period	$	34,069		$	17,260

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, 2013, 2012 and 2011, included in the 2013 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

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. Alagasco’s current RSE order has a term extending through September 30, 2018 and will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. The previous allowed range of return on average common equity was 13.15 percent to 13.65 percent through December 31, 2013. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months ended March 31, 2014 and 2013, Alagasco had net pre-tax reductions in revenues of $16.2 million and $2.4 million, respectively, to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, an $8.5 million decrease, $10.3 million increase and $7.8 million increase in revenues became effective January 1, 2014, December 1, 2013 and 2012, respectively. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments.

The inflation-based Cost Control Mechanism (CCM), established by the APSC, allows for annual increases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense (Base Year) inflation-adjusted using the June Consumer Price Index For All Urban Consumers each rate year plus or minus 1.75 percent (Index Range). If rate year O&M expense falls within the Index Range, no adjustment is required. If rate year O&M expense exceeds the Index Range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent that rate year O&M is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation.

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

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

12

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

3. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with two of its active counterparties and in a net loss position with the remaining twelve at March 31, 2014. The largest counterparty net gain position at March 31, 2014, Macquarie Bank Limited, constituted approximately $3.0 million of Energen Resources’ total net loss on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. The effective portion of the gain or loss on the derivative instrument was recognized in accumulated other comprehensive income as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value was required to be recognized in operating revenues immediately. All other derivative transactions not designated as cash flow hedge accounting are accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.

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

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

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The following tables detail the fair values of derivative commodity instruments on the balance sheets:

(in thousands)	March 31, 2014
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	17,522
Long-term asset derivative instruments	4,989
Total derivative assets	22,511
Accounts receivable	(14,165		)	*
Long-term asset derivative instruments	(2,351		)	*
Accounts payable	(52,602		)
Long-term liability derivative instruments	(802		)
Total derivative liabilities	(69,920		)
Total derivatives not designated	$	(47,409	)

(in thousands)	December 31, 2013
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	36,224
Long-term asset derivative instruments	7,992
Total derivative assets	44,216
Accounts receivable	(18,761		)	*
Long-term asset derivative instruments	(2,553		)	*
Accounts payable	(30,302		)
Total derivative liabilities	(51,616		)
Total derivatives not designated	$	(7,400	)

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

The Company had a net $6.7 million and a net $8.2 million deferred tax liability included in current deferred income taxes on the balance sheets related to derivative items included in accumulated other comprehensive income as of March 31, 2014, and December 31, 2013, respectively.

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

(in thousands)	Location on Statements of Income	Three months ended March 31, 2014		Three months ended March 31, 2013
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $1 and ($16,424)	—	$	2	$	(26,798	)
Gain reclassified from accumulated other comprehensive income into income (effective portion)	Operating revenues	$	4,054	$	17,824
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	—	$	(534	)

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

(in thousands)	Location on Statements of Income	Three months ended March 31, 2014			Three months ended March 31, 2013
Loss recognized in income on derivatives	Operating revenues	$	(57,446	)	$	(31,501	)

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As of March 31, 2014, $10.9 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of March 31, 2014, the Company had 7.4 million barrels (MMBbl) and 7.3 MMBbl of oil swaps which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 44.9 billion cubic feet (Bcf) and 12.0 Bcf of natural gas and natural gas basis swaps which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. During 2013, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being sold. This discontinuance of hedge accounting resulted in $2.6 million after-tax losses being recognized into operating revenues during the three months ended March 31, 2014.

As of March 31, 2014, Energen Resources entered into the following transactions for the remainder of 2014 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2014	7,392	MBbl	$92.65 Bbl	NYMEX Swaps
2015	7,260	MBbl	$89.07 Bbl	NYMEX Swaps
Natural Gas
2014	7.9	Bcf	$4.55 Mcf	NYMEX Swaps
2014	23.5	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
2014	7.4	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	12.0	Bcf	$4.05 Mcf	Basin Specific Swaps - San Juan
Natural Gas Basis Differential
2014	4.6	Bcf	$(0.09) Mcf	San Juan Basis Swaps
2014	1.5	Bcf	$(0.17) Mcf	Permian Basis Swaps

As of March 31, 2014, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015.

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

	March 31, 2014
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(6,646	)	$	10,003		$	3,357
Noncurrent assets	1,192			1,446			2,638
Current liabilities	(42,531		)	(10,071		)	(52,602		)
Noncurrent liabilities	(802		)	—			(802		)
Net derivative asset (liability)	$	(48,787	)	$	1,378		$	(47,409	)

	December 31, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,658	)	$	19,121		$	17,463
Noncurrent assets	4,383			1,056			5,439
Current liabilities	(28,414		)	(1,888		)	(30,302		)
Net derivative asset (liability)	$	(25,689	)	$	18,289		$	(7,400	)

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

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $18 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $18 million associated with open Level 3 mark-to-market

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derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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

	Three months ended			Three months ended
(in thousands)	March 31, 2014			March 31, 2013
Balance at beginning of period	$	18,289		$	89,019
Realized gains (losses)	(3,019		)	27,107
Unrealized losses relating to instruments held at the reporting date*	(16,835		)	(63,482		)
Settlements during period	2,943			(26,185		)
Balance at end of period	$	1,378		$	26,459

*Includes $13.2 million and $12.4 million in mark-to-market losses for the three months ended March 31, 2014 and 2013, respectively.

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

(in thousands)	Fair Value as of March 31, 2014			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2014	$	5,326		Discounted Cash Flow	Forward Basis	($0.06 - $0.09) Mcf
2015	$	(129	)	Discounted Cash Flow	Forward Basis	($0.14) Mcf
Natural Gas Basis - Permian
2014	$	(3,819	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.13) Mcf

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

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

	March 31, 2014
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	22,511	$	(16,516	)	$	5,995	$	—	$	—	$	5,995
Derivative liabilities	$	69,920	$	(16,516	)	$	53,404	$	—	$	—	$	53,404

	December 31, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	44,215	$	(21,313	)	$	22,902	$	—	$	—	$	22,902
Derivative liabilities	$	51,615	$	(21,313	)	$	30,302	$	—	$	—	$	30,302

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4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended					Three months ended
(in thousands, except per share amounts)	March 31, 2014					March 31, 2013
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	53,316	72,629	$	0.73	$	56,692	72,143	$	0.79
Effect of dilutive securities
Stock options			296					144
Non-vested restricted stock			44					1
Performance share awards			76					—
Diluted EPS	$	53,316	73,045	$	0.73	$	56,692	72,288	$	0.78

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

	Three months ended March 31,
(in thousands)	2014	2013
Stock options	111,554	988,087
Performance share awards	68,250	161,249

5. SEGMENT INFORMATION

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

	Three months ended
	March 31,
(in thousands)	2014			2013
Operating revenues from continuing operations
Oil and gas operations	$	297,278		$	236,331
Natural gas distribution	263,900			237,685
Total	$	561,178		$	474,016
Operating income (loss) from continuing operations
Oil and gas operations	$	33,548		$	23,181
Natural gas distribution	72,351			79,293
Eliminations and corporate expenses	(1,300		)	(284		)
Total	$	104,599		$	102,190
Other income (expense) from continuing operations
Oil and gas operations	$	(13,819	)	$	(12,031	)
Natural gas distribution	(2,839		)	(3,130		)
Eliminations and other	348			74
Total	$	(16,310	)	$	(15,087	)
Income from continuing operations before income taxes	$	88,289		$	87,103

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(in thousands)	March 31, 2014		December 31, 2013
Identifiable assets
Oil and gas operations	$	5,521,883	$	5,379,135
Natural gas distribution	1,209,375		1,193,413
Eliminations and other	49,132		49,664
Total	$	6,780,390	$	6,622,212

6. STOCK COMPENSATION

Stock Incentive Plan

Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options and non-qualified stock options to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option was granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 107,868 non-qualified option shares during the first quarter of 2014 with a grant-date fair value of $27.57.

Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted stock units. In January 2014, the Company awarded 41,664 restricted stock units with a grant-date fair value of $70.68. These awards were valued based on the quoted market price of the Company’s common stock at the date of grant and have a three year vesting period.

Performance Share Awards: The Stock Incentive Plan also provides for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Company common stock. Performance share awards are valued using the Monte Carlo model which uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. The Company granted 287 performance share awards during the first quarter of 2014 with a two year vesting period and a grant-date fair value of $118.99. The Company also granted 63,842 performance share awards during the first quarter of 2014 with a three year award period and a grant-date fair value of $93.13.

Stock Appreciation Rights Plan

The Energen Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company common stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 62,749 awards during the first quarter of 2014. These awards had a fair value of $35.04 as of March 31, 2014.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which are re-measured each reporting period and settle in cash at completion of the vesting period. During the first quarter of 2014, Energen Resources awarded 28,840 Petrotech units with a fair value of $79.18 as of March 31, 2014, none of which included a market condition. Also awarded were 36,920 Petrotech units which included a market condition and had a fair value of $115.94 as of March 31, 2014. These awards have a three year vesting period.

Stock Repurchase Program

During the three months ended March 31, 2014, the Company had non-cash purchases of approximately $0.3 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

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7. EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost for the Company’s two defined benefit non-contributory pension plans and certain non-qualified supplemental pension plans were as follows:

	Three months ended March 31,
(in thousands)	2014			2013
Components of net periodic benefit cost:
Service cost	$	3,003		$	3,602
Interest cost	2,575			2,718
Expected long-term return on assets	(2,848		)	(3,713		)
Actuarial loss amortization	2,256			3,690
Prior service cost amortization	118			122
Settlement charge	7,262			144
Net periodic expense	$	12,366		$	6,563

The Company anticipates required contributions of approximately $0.5 million during 2014 to the qualified pension plans. The Company expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $3.0 million to the qualified pension plans in January 2014. During 2014, the Company may make discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. For the three months ended March 31, 2014, the Company made benefit payments aggregating $33,000 to retirees from the non-qualified supplemental retirement plans and expects to make additional benefit payments of approximately $0.2 million through the remainder of 2014. In the first quarter of 2014, the Company incurred a settlement charge of $17.1 million for the payment of lump sums from the qualified defined benefit pension plans, of which $6.9 million was expensed and $10.2 million was recognized as a pension asset in regulatory assets at Alagasco. Also in the first quarter of 2014, the Company incurred a settlement charge of $0.4 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the non-qualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension asset in regulatory assets at Alagasco.

The components of net periodic benefit cost for the Company’s postretirement benefit plans were as follows:

	Three months ended March 31,
(in thousands)	2014			2013
Components of net periodic benefit cost:
Service cost	$	170		$	444
Interest cost	754			869
Expected long-term return on assets	(1,412		)	(1,242		)
Actuarial gain amortization	(520		)	—
Transition obligation amortization	27			324
Net periodic (income) expense	$	(981	)	$	395

There are no required contributions to the postretirement benefit plans during 2014.

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 6.4 million barrels of oil equivalent (MMBOE) through September 2017.

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Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $150 million through September 2024. During the three months ended March 31, 2014 and 2013, Alagasco recognized approximately $13.4 million and $14.4 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 123 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At March 31, 2014, the fixed price purchases under these guarantees had a maximum term outstanding through December 2014 with an aggregate purchase price and market value of $0.3 million.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings and the Company has accrued a provision for its estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. The Company recognizes its liability for contingencies when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.

On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco is cooperating with the National Transportation Safety Board which is investigating the incident. Alagasco has been named as a defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against Alagasco.

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

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

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $2.1 million of which $1.9 million has been incurred and $0.2 million has been reserved.

During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency (EPA) regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party (PRP) under The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Due to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site.

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the EPA, Alagasco and the current site owner.

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In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the 35thAvenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35thAvenue Superfund Site. In September 2013, Alagasco received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a PRP under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has discussed its designation as a PRP further with the EPA, and Alagasco has requested additional information from the EPA regarding its designation as a PRP. Alagasco has also been approached by a law firm regarding entry into an agreement to toll the statute of limitations with potential plaintiffs related to purported damages allegedly incurred by such potential plaintiffs in connection with the 35th Avenue Superfund Site, and is considering whether to enter into such a tolling arrangement. Alagasco has not been provided information at this time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action, and therefore Alagasco has not agreed to undertake the proposed removal activities and no amount has been accrued as of March 31, 2014.

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

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of March 31, 2014.

9. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, was approximately $1,421.2 million and $1,420.7 million and had a carrying value of $1,388.9 million and $1,403.9 million at March 31, 2014 and December 31, 2013, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $263.5 million and $258.8 million and had a carrying value of $249.9 million at March 31, 2014 and December 31, 2013, respectively. The fair values are based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

At March 31, 2014, the Company had interest rate swap agreements with a notional of $200 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 2.6675 percent. The fair value of the Company’s interest rate swap was a $1.6 million and a $1.8 million liability at March 31, 2014 and December 31, 2013, respectively, and is classified as Level 2 fair value liability. The fair value of the Company’s interest rate swap is recognized on a gross basis on the consolidated balance sheet.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At March 31, 2014 and December 31, 2013, Alagasco’s finance receivable totaled $10.5 million and $10.8 million, respectively. These finance receivables currently have an average balance of approximately $3,000 with terms of up to 84 months. Financing is available only to qualified customers who meet creditworthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to a third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.3 million and $0.4 million as of March 31, 2014 and December 31, 2013, respectively.

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

(in thousands)
Allowance for credit losses as of December 31, 2013	$	423
Provision	(124		)
Allowance for credit losses as of March 31, 2014	$	299

10. EXPLORATORY COSTS    

The Company capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, the Company continues to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in oil and gas properties in the balance sheets. If the exploratory well is determined to be impaired, the impaired costs are charged to operations and maintenance expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred.

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:

	Three months ended			Three months ended
(in thousands)	March 31, 2014			March 31, 2013
Capitalized exploratory well costs at beginning of period	$	57,600		$	79,791
Additions pending determination of proved reserves	164,842			95,861
Reclassifications due to determination of proved reserves	(112,474		)	(69,477		)
Capitalized exploratory well costs at end of period	$	109,968		$	106,175

The following table sets forth capitalized exploratory wells costs and includes amounts capitalized for a period greater than one year:

	Three months ended		Three months ended
(in thousands)	March 31, 2014		March 31, 2013
Exploratory wells in progress	$	62,280	$	21,676
Capitalized exploratory well costs capitalized for a period of one year or less	46,460		83,301
Capitalized exploratory well costs for a period greater than one year	1,228		1,198
Total capitalized exploratory well costs	$	109,968	$	106,175

At March 31, 2014, the Company had 45 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are primarily located in the Permian Basin. The Company has one gross well capitalized greater than a year which is pending results from completion and testing. This well is currently waiting on facilities.

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11. REGULATORY ASSETS AND LIABILITIES

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

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

12. ASSET RETIREMENT OBLIGATIONS

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

During the three months ended March 31, 2014, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance as of December 31, 2013	$	108,533
Liabilities incurred	766
Liabilities settled	(413		)
Accretion expense	1,843
Balance as of March 31, 2014	$	110,729

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $27.8 million and $27.5 million to purge and cap its gas pipelines upon abandonment and to remediate other related obligations, as a regulatory liability as of March 31, 2014 and December 31, 2013, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $4.0 million and $4.6 million as of March 31, 2014 and December 31, 2013, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

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13. ACQUISITION AND DISPOSITION OF PROPERTIES

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

During 2013, Energen also completed a total of approximately $31.3 million in various purchases of unproved leasehold properties.

14. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2013	$	12,178		$	(32,245	)	$	(20,067	)
Other comprehensive loss before reclassifications	(113		)	—			(113		)
Amounts reclassified from accumulated other comprehensive income (loss)	(2,224		)	5,613			3,389
Change in accumulated other comprehensive income (loss)	(2,337		)	5,613			3,276
Balance as of March 31, 2014	$	9,841		$	(26,632	)	$	(16,791	)

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

	Three months ended			Three months ended
	March 31, 2014			March 31, 2013
(in thousands)	Amounts Reclassified						Line Item Where Presented
Gains and (losses) on cash flow hedges:
Derivative commodity instruments	$	4,054		$	17,290		Operating revenues
Interest rate swap	(446		)	(409		)	Interest expense
Total cash flow hedges	3,608			16,881
Income tax expense	(1,384		)	(6,427		)
Net of tax	2,224			10,454
Pension and postretirement plans:
Transition obligation	(10		)	(74		)	Operations and maintenance
Prior service cost	(74		)	(78		)	Operations and maintenance
Actuarial losses*	(1,290		)	(2,254		)	Operations and maintenance
Actuarial losses on settlement charges	(7,262		)	—			Operations and maintenance
Actuarial losses on settlement charges*	—			(375		)	Regulatory asset
Total pension and postretirement plans	(8,636		)	(2,781		)
Income tax benefit	3,023			973
Net of tax	(5,613		)	(1,808		)
Total reclassifications for the period	$	(3,389	)	$	8,646

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

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15. DISCONTINUED OPERATIONS

In March 2014, Energen Resources completed the sale on its North Louisiana/East Texas natural gas and oil properties for $30.3 million (subject to closing adjustments). The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the first quarter of 2014 of $1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. Energen Resources also recognized non-cash impairment writedowns on these properties in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment writedowns are classified as Level 3 fair value. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

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

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

(in thousands)	March 31, 2014
	Black Warrior Basin			North Louisiana/East Texas			Total
Accounts receivable	$	—		$	1,670		$	1,670
Inventories	—			68			68
Other property, net	—			133			133
Total assets held-for-sale	—			1,871			1,871
Accounts payable	(2,172		)	(10		)	(2,182		)
Royalty payable	—			(1,221		)	(1,221		)
Other current liabilities	—			(7		)	(7		)
Total liabilities held-for-sale	(2,172		)	(1,238		)	(3,410		)
Total net held-for-sale properties	$	(2,172	)	$	633		$	(1,539	)

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

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	Three months ended
	March 31,
(in thousands, except per share data)	2014			2013
Oil and gas revenues	$	4,821		$	18,663
Pretax income (loss) from discontinued operations	$	(2,078	)	$	3,168
Income tax expense (benefit)	(952		)	1,170
Income (Loss) From Discontinued Operations	$	(1,126	)	$	1,998
Loss on disposal of discontinued operations	$	(1,667	)	$	—
Income tax benefit	(617		)	—
Loss on Disposal of Discontinued Operations	$	(1,050	)	$	—
Total Income (Loss) From Discontinued Operations	$	(2,176	)	$	1,998
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
Loss on Disposal of Discontinued Operations	(0.01		)	—
Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
Loss on Disposal of Discontinued Operations	(0.01		)	—
Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03

16. RECENTLY ISSUED ACCOUNTING STANDARDS

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held-for-sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment is effective for all annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The Company is currently evaluating the impact of this ASU.

17. SUBSEQUENT EVENTS

In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness.

Due to the sale of Alagasco discussed above, the Company has separated its qualified defined benefit plans and the postretirement health care and life insurance benefit plans into separate plans established for Energen and Alagasco. These separate plans will be remeasured effective April 30, 2014.  

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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 $53.3 million ($0.73 per diluted share) for the three months ended March 31, 2014 compared with net income of $56.7 million ($0.78 per diluted share) for the same period in the prior year. In the first quarter of 2014, Energen’s income from continuing operations totaled $55.5 million ($0.76 per diluted share) and compared with income from continuing operations of $54.7 million ($0.75 per diluted share) in the same period a year ago. Loss from discontinued operations for the current-quarter period was $2.2 million as compared with income of $2.0 million from the prior-year first quarter. Energen Resources Corporation, Energen’s oil and gas subsidiary, had net income for the three months ended March 31, 2014, of $10.0 million as compared with net income of $8.8 million in the same quarter in the previous year. Energen Resources generated net income from continuing operations of $12.2 million in the current quarter as compared with income of $6.8 million in the same quarter last year. This increase in net income from continuing operations was primarily the result of higher oil, natural gas liquids and natural gas production volumes (approximately $30 million after-tax), increased oil and natural gas commodity prices (approximately $5 million after-tax) and a year-over-year after-tax $4.4 million non-cash mark-to-market increase in derivatives (resulting from an after-tax $21.5 million non-cash mark-to-market loss on derivatives for the first quarter of 2014 and an after-tax $26 million non-cash mark-to-market loss on derivatives for the first quarter of 2013). Negatively affecting net income was the impact of higher depreciation, depletion and amortization (DD&A) expense (approximately $19 million after-tax), higher exploration expense (approximately $7 million after-tax), increased production taxes (approximately $4 million after-tax), and higher administrative expense (approximately $3 million after-tax). Energen’s natural gas utility, Alagasco, reported net income of $43.0 million in the first quarter of 2014 compared to net income of $47.2 million in the same period last year.

Oil and Gas Operations

Revenues from continuing oil and gas operations rose 25.8 percent to $297.3 million for the three months ended March 31, 2014 largely as a result of higher production volumes, increased realized oil and natural gas commodity prices and the non-cash mark-to-market increase in derivatives partially offset by decreased realized natural gas liquids commodity prices. During the current quarter, revenue per unit of production for oil rose 1.4 percent to $86.86 per barrel, while natural gas liquids revenue per unit of production fell 2.6 percent to an average price of $0.75 per gallon. Natural gas revenue per unit of production increased 8.2 percent to $4.51 per thousand cubic feet (Mcf). Revenues per unit of production include realized prices and the effects of designated cash flow hedges and exclude the impact of the non-cash mark-to-market hedges.

Production from continuing operations for the current quarter increased largely due to higher volumes related to increased field development in certain Permian Basin liquids-rich properties partially offset by normal production declines. Oil volumes in the first quarter increased 18.9 percent to 2,751 thousand barrels (MBbl), natural gas liquids production rose 37.3 percent to 37.9 million gallons (MMgal) and natural gas production in the first quarter rose 2.2 percent to 14.1 billion cubic feet (Bcf). Oil and natural gas liquids comprised approximately 61 percent of Energen Resources’ production from continuing operations for the current quarter.

Operations and maintenance (O&M) expense increased $15.1 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) decreased $0.1 million for the quarter largely due to lower ad valorem taxes (approximately $1.9 million) and decreased equipment rental expense (approximately $1.6 million) partially offset by higher workover and repair expense (approximately $1.4 million), additional other O&M expense (approximately $1.1 million) and increased labor costs (approximately $0.6 million). On a per unit basis, the average lease operating expense (excluding production taxes) for the current quarter was $12.49 per barrel of oil equivalent (BOE) as compared to $14.25 per BOE in the same period a year ago. Administrative expense increased $4.0 million for the three months ended March 31, 2014 largely due to increased costs from the Company’s benefit and performance-based compensation plans (approximately $4.1 million) and higher labor costs (approximately $1.7 million) partially offset by decreased legal expenses (approximately $1.2 million).Exploration expense increased $11.3 million in the first quarter of 2014 primarily due to higher delay rental payments and seismic costs.

Energen Resources’ DD&A expense for the quarter rose $29.3 million. The average depletion rate for the current quarter was $20.52 per BOE as compared to $17.84 per BOE in the same period a year ago. The increase in the current quarter per unit DD&A rate, which contributed approximately $16.1 million to the increase in DD&A expense, was largely due to higher rates resulting from an increase in development costs and greater oil volumes as a percent of total production. Higher production volumes contributed approximately $13.1 million to the increase in DD&A expense for the quarter.

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Energen Resources’ expense for taxes other than income taxes was $6.0 million higher in the three months ended March 31, 2014 largely due to production-related taxes. In the quarter, higher oil, natural gas liquids and natural gas commodity market prices contributed approximately $4.1 million to the increase in production-related taxes and increased production volumes contributed approximately $1.9 million to the increase. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues increased $26.2 million for the quarter largely due to higher customer usage combined with an increase in the pass-through of gas costs partially offset by adjustments from the utility’s rate setting mechanisms. During the first quarter of 2014, Alagasco had a net $16.2 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. 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. Weather, for the current quarter, that was 26.2 percent colder compared with the same period in the prior year contributed to a 25.7 percent increase in residential sales volumes and a 26.3 percent rise in commercial and industrial customer sales volumes. Transportation volumes decreased slightly in period comparisons. Increased gas purchase volumes and higher gas costs resulted in a 34.2 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 cost fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense declined 4.7 percent in the current quarter primarily due to lower labor-related costs (approximately $1.9 million).

A 5.6 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 $0.9 million in the first quarter of 2014 largely due to the December 2013, issuance of $600 million in Senior Term Loans with a floating interest rate due March 31, 2014 through December 17, 2017. The $600 million issuance includes $400 million with a floating rate of the London Interbank Offered Rate plus 1.625 percent, currently 1.778 percent at March 31, 2014 and $200 million swapped to a fixed rate at 2.6675 percent. These increases in interest expense for 2014 were partially offset by the October 2013 repayment of $50 million of 5 percent Notes, the December 2013 repayment of the Senior Term Loans of $300 million issued in November 2011 and lower short-term borrowings. Income tax expense for the Company increased $0.4 million in the current quarter largely due to higher pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $297.0 million as compared to $261.5 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 $281.0 million for the three months ended March 31, 2014 primarily due to additions of property, plant and equipment of $289 million. Energen Resources incurred on a cash basis $273 millionin capital expenditures primarily related to the acquisition and development of oil and gas properties. Energen Resources had cash proceeds in the first quarter of $7.3 million primarily from the sale of the North Louisiana/East Texas properties. Utility capital expenditures on a cash basis totaled $15.5 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 $13.8 million from financing activities in the year-to-date primarily due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders and the reduction of long-term debt for current maturities.

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Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2014, the Company expects its oil and gas capital spending to total approximately $1.3 billion, primarily all of which is for existing properties. On an annual basis, the development and exploration expenditures cannot be reasonably segregated as drilling and development throughout the course of the year may change the classification of locations currently identified as exploratory. 

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

Discontinued Operations

In March 2014, Energen Resources completed the sale on its North Louisiana/East Texas natural gas and oil properties for $30.3 million (subject to closing adjustments). The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the first quarter of 2014 of $1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. Energen Resources also recognized non-cash impairment writedowns on these properties in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

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

Natural Gas Distribution

In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness.

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending through September 30, 2018 and will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. The previous allowed range of return on average common equity was 13.15 percent to 13.65 percent through December 31, 2013. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments.

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 $14.2 million, $16.3 million, $14.2 million, $22.2 million and $2.7 million for the periods January through March 2014, the years ended December 31, 2013, 2012, 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $12.4 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $28.8 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through 2019 through lower tariff rates. The total amount refundable to customers is subject to adjustments over the remaining five year period for charges made to the Enhanced Stability Reserve and

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other APSC approved charges. The refunds as of March 31, 2014 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 maintains an investment in storage gas that is expected to average approximately $40 million in 2014 but will vary depending upon the price of natural gas. During 2014, Alagasco plans to invest approximately $74 million in capital expenditures for the normal needs of its distribution, support systems and technology-related projects and the construction of a service center to replace the Metro Operations Center sold during 2013. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities. Alagasco also may issue long-term debt periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.

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

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. At March 31, 2014, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with two of its active counterparties and in a net loss position with the remaining twelve at March 31, 2014. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

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Energen Resources entered into the following transactions for the remainder of 2014 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2014	7,392	MBbl	$92.65 Bbl	NYMEX Swaps
2015	7,260	MBbl	$89.07 Bbl	NYMEX Swaps
2015	1,020	MBbl*	$90.99 Bbl	NYMEX Swaps
Oil Basis Differential
2014	600	MBbl*	$(3.30) Bbl	WTS/WTI Basis Swaps**
2014	1,200	MBbl*	$(3.08) Bbl	WTI/WTI Basis Swaps***
Natural Gas Liquids
2014	46	MBbl*	$0.93 Gal	Liquids Swaps
Natural Gas
2014	7.9	Bcf	$4.55 Mcf	NYMEX Swaps
2014	23.5	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
2014	7.4	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	12.0	Bcf	$4.05 Mcf	Basin Specific Swaps - San Juan
2015	11.0	Bcf*	$4.23 Mcf	Basin Specific Swaps - San Juan
2015	6.0	Bcf*	$4.20 Mcf	Basin Specific Swaps - Permian
Natural Gas Basis Differential
2014	4.6	Bcf	$(0.09) Mcf	San Juan Basis Swaps
2014	1.5	Bcf	$(0.17) Mcf	Permian Basis Swaps
*Contract entered into subsequent to March 31, 2014
**WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
***WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

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

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

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

	March 31, 2014
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(6,646	)	$	10,003		$	3,357
Noncurrent assets	1,192			1,446			2,638
Current liabilities	(42,531		)	(10,071		)	(52,602		)
Noncurrent liabilities	(802		)	—			(802		)
Net derivative asset (liability)	$	(48,787	)	$	1,378		$	(47,409	)

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	December 31, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,658	)	$	19,121		$	17,463
Noncurrent assets	4,383			1,056			5,439
Current liabilities	(28,414		)	(1,888		)	(30,302		)
Net derivative asset (liability)	$	(25,689	)	$	18,289		$	(7,400	)

*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.

Level 3 assets and liabilities as of March 31, 2014, 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 $18 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $18 million associated with open Level 3 mark-to-market derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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. However, the Company could experience increased costs and reduced liquidity in the markets as a result of the new rules and regulations, which could reduce hedging opportunities and negatively affect the Company’s revenues and cash flows.

Credit Facilities and Working Capital

On October 30, 2012, Energen and Alagasco entered into $1.25 billion and $100 million, respectively, five-year syndicated unsecured credit facilities (syndicated credit facilities) with domestic and foreign lenders. Energen’s obligations under the $1.25 billion syndicated credit facility are unconditionally guaranteed by Energen Resources. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of not more than 65 percent for both the Company and Alagasco.

At March 31, 2014, the Company reported negative working capital of $771.5 million arising from current liabilities of $1,210.5 million exceeding current assets of $439.0 million. The negative working capital is primarily due to a $36 million increase in borrowings during the three months ended March 31, 2014 and a $628 million increase in borrowings during 2012 partially offset by a $104 million decrease in borrowings during 2013 under the syndicated credit facilities and in support of Energen’s capital projects. Generally accepted accounting principles require short-term classification for obligations such as these that are subject to the execution of individual notes with maturity dates less than one year. The syndicated credit facilities were entered into on October 30, 2012 and have a five-year term.

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, 2014 include $3.4 million and $52.6 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 $12.4 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates. Energen and Alagasco rely upon cash flows from operations supplemented by their syndicated credit facilities to fund working capital needs. Negative working capital is expected to be positively impacted from the sale of Alagasco as previously discussed.

Credit Ratings

On April 8, 2014, following the announced sale of Alagasco, Moody’s Investors Service lowered Energen’s senior unsecured credit rating from Baa3 to Ba1 with a negative outlook. Alagasco’s senior unsecured credit rating, which is investment grade with a negative outlook, has been placed under review. On December 16, 2013, Standard & Poor’s (S&P) lowered its credit ratings for Energen and Alagasco from investment grade with a stable outlook to investment grade with a negative outlook. On April 9, 2014, S&P placed

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Energen and Alagasco on CreditWatch with negative implications for Energen and positive implications for Alagasco. S&P expects to resolve the CreditWatch around the time of the close of the sale of Alagasco.

Dividends

Energen’s dividend policy is under review in connection with the pending sale of Alagasco. Dividends for the first quarter of 2014 were $0.15 per share on the Company’s common stock and a $0.15 per share dividend has been declared for the second quarter of 2014. Subsequent to the sale of Alagasco, the Company expects to substantially reduce the amount of its dividend payments with a focus on further development and exploration of its oil and natural gas properties. 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. There have been no material changes to the contractual cash obligations of the Company since December 31, 2013.

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, 2014.

Recent Accounting Standards Updates

See Note 16, Recently Issued Accounting Standards, in the Notes to Unaudited Condensed Financial Statements for information regarding recently issued accounting standards.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties (many of which are beyond our control) that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, natural gas liquids and natural gas, 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, the proposed sale of Alagasco to The Laclede Group, Inc., 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

33

or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors which may affect the Company’s future business and financial performance.

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

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

The Company is exposed to counterparty credit risk as a result of its concentrated customer base: Revenues and related accounts receivable from oil and natural gas operations primarily are generated from the sale of produced oil, natural gas liquids and natural gas 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 natural 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.

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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 natural 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 natural gas production activities of Energen Resources and the natural gas distribution activities of Alagasco are a variety of hazards and operation risks, such as:

• Pipeline and storage leaks, ruptures and spills;

• Equipment malfunctions and mechanical failures;

• Fires and explosions;

• Well blowouts, explosions and cratering; and

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

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

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

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

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

Successful completion of the Company’s pending sale of Alagasco is subject to various risks and conditions: In April 2014, the Company signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. The Company plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness. The sale of Alagasco involves various inherent risks, such as the Company’s ability to obtain regulatory approvals from the Alabama Public Service Commission and under the Hart-Scott-Rodino Antitrust Improvement Act; the timing of and conditions imposed upon the Company by regulators in connection with such approvals; and satisfaction by the parties of contractual conditions to closing.

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SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended
	March 31,
(in thousands, except sales price data)	2014			2013
Oil and Gas Operations
Operating revenues from continuing operations
Oil	$	217,493		$	161,551
Natural gas liquids	28,686			21,116
Natural gas	51,252			53,216
Other	(153)			448
Total	$	297,278		$	236,331
Non-cash mark-to-market gains (losses) (included in operating revenues from continuing operations above)
Oil	$	(21,464	)	$	(36,652	)
Natural gas liquids	287			(21		)
Natural gas	(12,504		)	(4,375		)
Total	$	(33,681	)	$	(41,048	)
Production volumes from continuing operations
Oil (MBbl)	2,751			2,314
Natural gas liquids (MMgal)	37.9			27.6
Natural gas (MMcf)	14,124			13,818
Production volumes from continuing operations (MBOE)	6,008			5,273
Total production volumes (MBOE)	6,162			5,921
Revenue per unit of production excluding effects of non-cash mark-to-market derivative instruments
Oil (per barrel)	$	86.86		$	85.65
Natural gas liquids (per gallon)	$	0.75		$	0.77
Natural gas (per Mcf)	$	4.51		$	4.17
Revenue per unit of production excluding effects of all derivative instruments
Oil (per barrel)	$	92.24		$	82.44
Natural gas liquids (per gallon)	$	0.74		$	0.68
Natural gas (per Mcf)	$	4.88		$	3.29
Other data from continuing operations
Lease operating expense
Lease operating expense and other	$	75,012		$	75,155
Production taxes	19,756			13,763
Total	$	94,768		$	88,918
Depreciation, depletion and amortization	$	124,372		$	95,099
Capital expenditures	$	271,696		$	285,053
Exploration expense	$	12,814		$	1,498
Operating income	$	33,548		$	23,181

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Natural Gas Distribution
Operating revenues
Residential	$	191,611		$	162,739
Commercial and industrial	68,992			57,599
Transportation	18,034			18,240
Other	(14,737		)	(893		)
Total	$	263,900		$	237,685
Gas delivery volumes (MMcf)
Residential	13,053			10,382
Commercial and industrial	5,315			4,207
Transportation	12,782			12,790
Total	31,150			27,379
Other data
Depreciation and amortization	$	11,325		$	10,729
Capital expenditures	$	13,594		$	19,697
Operating income	$	72,351		$	79,293

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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 natural gas production. Historically, prices received for oil and natural 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 the 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 on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by the Company. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. All hedge transactions are subject to the Company’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. As of March 31, 2014, 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, 2014 primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at March 31, 2014 was 1.40 percent. The Company’s interest rate exposure on long-term debt as of March 31, 2014 was minimal since approximately 86 percent of long-term debt obligations were at fixed rates.

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ITEM 4. CONTROLS AND PROCEDURES

Energen Corporation

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

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

Alabama Gas Corporation

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

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

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PART II: OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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. Various pending or threatened legal proceedings are in progress currently. See Note 8, Commitments and Contingencies, in the Notes to Financial Statements for further discussion with respect to legal proceedings.

ITEM 1A. RISK FACTORS

Except as discussed below, there have been no material changes to the risk factors of the Company since December 31, 2013.

Successful completion of the Company’s pending sale of Alagasco is subject to various risks and conditions:In April 2014, the Company signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. The Company plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness. The sale of Alagasco involves various inherent risks, such as the Company’s ability to obtain regulatory approvals from the Alabama Public Service Commission and under the Hart-Scott-Rodino Antitrust Improvement Act; the timing of and conditions imposed upon the Company by regulators in connection with such approvals; and satisfaction by the parties of contractual conditions to closing.

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	Maximum Number of Shares that May Yet Be Purchased Under the Plans**
January 1, 2014 through January 31, 2014	—		$	—	—	8,992,700
February 1, 2014 through February 28, 2014	1,742	*	69.62		—	8,992,700
March 1, 2014 through March 31, 2014	2,230	*	81.03		—	8,992,700
Total	3,972		$	76.03	—	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

10	-	Stock Purchase Agreement, dated as of April 5, 2014, by and among The Laclede Group, Inc., Energen Corporation and Alabama Gas Corporation, which was filed as Exhibit 2.1 to Energen’s and Alabama Gas Corporation’s Current Report on Form 8-K filed April 7, 2014
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, 2014 are formated in XBRL

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SIGNATURES

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

		ENERGEN CORPORATION ALABAMA GAS CORPORATION
May 9, 2014	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, 2014	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, 2014	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr. Vice President and Controller of Energen Corporation
May 9, 2014	By	/s/ Leonarda M. DiChiara
		Leonarda M. DiChiara Vice President and Controller of Alabama Gas Corporation

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EX-31.A

Exhibit 31(a)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

May 9, 2014	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, 2014	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, 2014	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, 2014	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, 2014, 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, 2014

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, 2014, 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, 2014

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 - Hedging Transactions (Details)	3 Months Ended
	Mar. 31, 2014 Mcf
Natural Gas | 2014 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	7,900,000
Average Contract Price, per Mcf	4.55
Natural Gas | 2014 | Basin Specific Swaps - San Juan
Derivative [Line Items]
Total Hedged Volumes	23,500,000
Average Contract Price, per Mcf	4.60
Natural Gas | 2014 | San Juan Basis Swaps
Derivative [Line Items]
Total Hedged Volumes	4,600,000
Average Contract Price, per Mcf	(0.09)
Natural Gas | 2014 | Permian Basis Swaps
Derivative [Line Items]
Total Hedged Volumes	1,500,000
Average Contract Price, per Mcf	(0.17)
Natural Gas | 2014 | Basin Specific Swaps - Permian
Derivative [Line Items]
Total Hedged Volumes	7,400,000
Average Contract Price, per Mcf	3.81
Natural Gas | 2015 | Basin Specific Swaps - San Juan
Derivative [Line Items]
Total Hedged Volumes	12,000,000
Average Contract Price, per Mcf	4.05
Crude Oil | 2014 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	7,392,000
Average Contract Price, per Bbl	92.65
Crude Oil | 2015 | NYMEX Swaps
Derivative [Line Items]
Total Hedged Volumes	7,260,000
Average Contract Price, per Bbl	89.07

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

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

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

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

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Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

During the three months ended March 31, 2014, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance as of December 31, 2013	$	108,533
Liabilities incurred	766
Liabilities settled	(413		)
Accretion expense	1,843
Balance as of March 31, 2014	$	110,729

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

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Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2013, 2012 and 2011, included in the 2013 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items.

Derivatives

Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with two of its active counterparties and in a net loss position with the remaining twelve at March 31, 2014. The largest counterparty net gain position at March 31, 2014, Macquarie Bank Limited, constituted approximately $3.0 million of Energen Resources’ total net loss on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. The effective portion of the gain or loss on the derivative instrument was recognized in accumulated other comprehensive income as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value was required to be recognized in operating revenues immediately. All other derivative transactions not designated as cash flow hedge accounting are accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.

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

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

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held-for-sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment is effective for all annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The Company is currently evaluating the impact of this ASU.

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Commitments and Contingencies - Environmental Matters (Details) (Mitchell County, Texas, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014 pit
Mitchell County, Texas
Environmental Exit Cost [Line Items]
Number of sites	9
Anticipated cost	$ 2.1
Costs incurred	1.9
Accrual for environmental loss contingencies	$ 0.2

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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
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Discounted Cash Flow Level 3 Natural Gas Basis - San Juan 2014	Mar. 31, 2014 Discounted Cash Flow Level 3 Natural Gas Basis - San Juan 2014 Minimum	Mar. 31, 2014 Discounted Cash Flow Level 3 Natural Gas Basis - San Juan 2014 Maximum	Mar. 31, 2014 Discounted Cash Flow Level 3 Natural Gas Basis - San Juan 2015	Mar. 31, 2014 Discounted Cash Flow Level 3 Natural Gas Basis - Permian 2014	Mar. 31, 2014 Discounted Cash Flow Level 3 Natural Gas Basis - Permian 2014 Minimum	Mar. 31, 2014 Discounted Cash Flow Level 3 Natural Gas Basis - Permian 2014 Maximum
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of March 31, 2014	$ 5,995	$ 22,902	$ 5,326			$ (129)	$ (3,819)
Fair Value as of March 31, 2014	$ (53,404)	$ (30,302)
Fair Value Inputs, Price Per Cubic Foot				0.06	0.09	0.14		0.12	0.13

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

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

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Financial Instruments (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2014 Maximum	Mar. 31, 2014 Senior Loans Swap	Mar. 31, 2014 Senior Loans Swap Level 2	Dec. 31, 2013 Senior Loans Swap Level 2	Mar. 31, 2014 Senior Loans Senior Term Loans, Due March 31, 2014 to November 29, 2016 Swap	Mar. 31, 2014 Alabama Gas Corporation	Dec. 31, 2013 Alabama Gas Corporation	Mar. 31, 2014 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Dec. 31, 2013 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Mar. 31, 2014 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure Alabama Gas Corporation	Dec. 31, 2013 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure Alabama Gas Corporation	Mar. 31, 2014 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Dec. 31, 2013 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Mar. 31, 2014 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure Alabama Gas Corporation	Dec. 31, 2013 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure Alabama Gas Corporation
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt fair value									$ 1,421,200,000	$ 1,420,700,000	$ 263,500,000	$ 258,800,000	$ 1,388,900,000	$ 1,403,900,000	$ 249,900,000	$ 249,900,000
Face amount						200,000,000
Interest rate			2.6675%
Interest rate cash flow hedge liability at fair value				1,600,000	1,800,000
Financing receivable							10,500,000	10,800,000
Financing receivable recorded investment average balance 0 to 60 days past due							3,000
Average finance receivable term		84 months
Time after which delinquent accounts are evaluated	90 days
Financing receivable recorded investment, equal to greater than 90 days past due							300,000	400,000
Financing Receivable, Allowance for Credit Losses [Roll Forward]
Allowance for credit losses as of December 31, 2013	423,000
Provision	(124,000)
Allowance for credit losses as of March 31, 2014	$ 299,000

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

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Stock Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended	1 Months Ended	3 Months Ended
	Mar. 31, 2014 Stock options	Jan. 31, 2014 Restricted Stock Units (RSUs)	Mar. 31, 2014 Restricted Stock Units (RSUs)	Mar. 31, 2014 Restricted Stock Units (RSUs) Petrotech Incentive Plan	Mar. 31, 2013 Restricted Stock Units (RSUs) Petrotech Incentive Plan	Mar. 31, 2014 Performance share awards 2 year vesting period	Mar. 31, 2014 Performance share awards 3 year vesting period	Mar. 31, 2014 Performance share awards Petrotech Incentive Plan 3 year vesting period	Mar. 31, 2014 Stock Appreciation Rights (SARs)	Mar. 31, 2014 Deferred Compensation
Share-based Compensation Arrangement by Share-based Payment Award
Vesting period	3 years		3 years			2 years	3 years	3 years	3 years
Expiration period	10 years
Grants in period, options	107,868
Grants in period, options, fair value	$ 27.57
Grants in period (in shares)		41,664			28,840	287	63,842	36,920	62,749
Grants in period, fair value (in dollars per share)		$ 70.68		$ 79.18		$ 118.99	$ 93.13	$ 115.94	$ 35.04
Noncash payments for repurchase of common stock										$ 0.3

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Regulatory Matters

3 Months Ended

Mar. 31, 2014

Regulated Operations [Abstract]

Regulatory Matters

REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. Alagasco’s current RSE order has a term extending through September 30, 2018 and will continue beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and Alagasco will consult in good faith with respect to modifications, if any. Effective January 1, 2014, Alagasco’s allowed range of return on average common equity is 10.5 percent to 10.95 percent with an adjusting point of 10.8 percent. The previous allowed range of return on average common equity was 13.15 percent to 13.65 percent through December 31, 2013. Alagasco is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco’s return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months ended March 31, 2014 and 2013, Alagasco had net pre-tax reductions in revenues of $16.2 million and $2.4 million, respectively, to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, an $8.5 million decrease, $10.3 million increase and $7.8 million increase in revenues became effective January 1, 2014, December 1, 2013 and 2012, respectively. The equity upon which a return will be permitted cannot exceed 56.5 percent of total capitalization, subject to certain adjustments.

The inflation-based Cost Control Mechanism (CCM), established by the APSC, allows for annual increases to operations and maintenance (O&M) expense. The CCM range is Alagasco’s 2007 actual rate year O&M expense (Base Year) inflation-adjusted using the June Consumer Price Index For All Urban Consumers each rate year plus or minus 1.75 percent (Index Range). If rate year O&M expense falls within the Index Range, no adjustment is required. If rate year O&M expense exceeds the Index Range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent that rate year O&M is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation.

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

The APSC approved an Enhanced Stability Reserve (ESR) in 1998, which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $275,000 and $412,500, respectively, during a rate year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $350,000 during a rate year. Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which prescribe the timing of recovery. Funding to the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, Alagasco expects to be able to recover underfunded ESR balances over a five year amortization period with an annual limitation of $660,000. Amounts in excess of this limitation are deferred for recovery in future years.

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

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Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2014

Pension Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

The components of net periodic benefit cost for the Company’s two defined benefit non-contributory pension plans and certain non-qualified supplemental pension plans were as follows:

	Three months ended March 31,
(in thousands)	2014			2013
Components of net periodic benefit cost:
Service cost	$	3,003		$	3,602
Interest cost	2,575			2,718
Expected long-term return on assets	(2,848		)	(3,713		)
Actuarial loss amortization	2,256			3,690
Prior service cost amortization	118			122
Settlement charge	7,262			144
Net periodic expense	$	12,366		$	6,563

Postretirement Benefit Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

The components of net periodic benefit cost for the Company’s postretirement benefit plans were as follows:

	Three months ended March 31,
(in thousands)	2014			2013
Components of net periodic benefit cost:
Service cost	$	170		$	444
Interest cost	754			869
Expected long-term return on assets	(1,412		)	(1,242		)
Actuarial gain amortization	(520		)	—
Transition obligation amortization	27			324
Net periodic (income) expense	$	(981	)	$	395

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three months ended
	March 31,
(in thousands)	2014			2013
Operating revenues from continuing operations
Oil and gas operations	$	297,278		$	236,331
Natural gas distribution	263,900			237,685
Total	$	561,178		$	474,016
Operating income (loss) from continuing operations
Oil and gas operations	$	33,548		$	23,181
Natural gas distribution	72,351			79,293
Eliminations and corporate expenses	(1,300		)	(284		)
Total	$	104,599		$	102,190
Other income (expense) from continuing operations
Oil and gas operations	$	(13,819	)	$	(12,031	)
Natural gas distribution	(2,839		)	(3,130		)
Eliminations and other	348			74
Total	$	(16,310	)	$	(15,087	)
Income from continuing operations before income taxes	$	88,289		$	87,103

(in thousands)	March 31, 2014		December 31, 2013
Identifiable assets
Oil and gas operations	$	5,521,883	$	5,379,135
Natural gas distribution	1,209,375		1,193,413
Eliminations and other	49,132		49,664
Total	$	6,780,390	$	6,622,212

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

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

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Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Allowance for Credit Losses on Financing Receivables

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

(in thousands)
Allowance for credit losses as of December 31, 2013	$	423
Provision	(124		)
Allowance for credit losses as of March 31, 2014	$	299

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Exploratory Costs (Tables)

3 Months Ended

Mar. 31, 2014

Extractive Industries [Abstract]

Schedule of Capitalized Exploratory Wells

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:

	Three months ended			Three months ended
(in thousands)	March 31, 2014			March 31, 2013
Capitalized exploratory well costs at beginning of period	$	57,600		$	79,791
Additions pending determination of proved reserves	164,842			95,861
Reclassifications due to determination of proved reserves	(112,474		)	(69,477		)
Capitalized exploratory well costs at end of period	$	109,968		$	106,175

The following table sets forth capitalized exploratory wells costs and includes amounts capitalized for a period greater than one year:

	Three months ended		Three months ended
(in thousands)	March 31, 2014		March 31, 2013
Exploratory wells in progress	$	62,280	$	21,676
Capitalized exploratory well costs capitalized for a period of one year or less	46,460		83,301
Capitalized exploratory well costs for a period greater than one year	1,228		1,198
Total capitalized exploratory well costs	$	109,968	$	106,175

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Basis of Presentation

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

BASIS OF PRESENTATION

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2013, 2012 and 2011, included in the 2013 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. All adjustments to the unaudited condensed financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consist of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

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

3 Months Ended

Mar. 31, 2014

Alabama Gas Corporation

Regulatory Assets and Liabilities [Line Items]

Schedule of Regulatory Assets and Liabilities

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

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

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Derivative Commodity Instruments - Derivatives Measured at Fair Value on a Recurring Basis (Details) (USD $)							3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Level 2 Fair Value, Measurements, Recurring		Dec. 31, 2013 Level 2 Fair Value, Measurements, Recurring		Mar. 31, 2014 Level 3	Mar. 31, 2014 Level 3 Fair Value, Measurements, Recurring		Dec. 31, 2013 Level 3 Fair Value, Measurements, Recurring		Mar. 31, 2014 Total Fair Value, Measurements, Recurring	Dec. 31, 2013 Total Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Current assets			$ (6,646,000)	[1]	$ (1,658,000)	[1]		$ 10,003,000	[1]	$ 19,121,000	[1]	$ 3,357,000	$ 17,463,000
Noncurrent assets	2,638,000	5,439,000	1,192,000	[1]	4,383,000	[1]		1,446,000	[1]	1,056,000	[1]	2,638,000	5,439,000
Current liabilities			(42,531,000)	[1]	(28,414,000)	[1]		(10,071,000)	[1]	(1,888,000)	[1]	(52,602,000)	(30,302,000)
Noncurrent liabilities	(1,011,000)	(398,000)	(802,000)	[1]				0	[1]			(802,000)
Net derivative asset (liability)			(48,787,000)	[1]	(25,689,000)	[1]		1,378,000	[1]	18,289,000	[1]	(47,409,000)	(7,400,000)
Impact on fair value of a 10 percent increase or decrease in commodity prices							18,000,000
Impact on results of operations of a 10 percent increase or decrease in commodity prices							$ 18,000,000

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

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

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Consolidated Condensed Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Revenues
Oil and gas operations	$ 297,278	$ 236,331
Natural gas distribution	263,900	237,685
Total operating revenues	561,178	474,016
Operating Expenses
Cost of gas	128,114	95,442
Operations and maintenance	155,072	140,712
Depreciation, depletion and amortization	135,697	105,828
Income taxes
Deferred	10,531	29,028
Taxes, other than income taxes	35,853	28,157
Accretion expense	1,843	1,687
Total operating expenses	456,579	371,826
Operating Income	104,599	102,190
Other Income (Expense)
Interest expense	(17,640)	(16,752)
Other income	1,384	1,734
Other expense	(54)	(69)
Total other expense	(16,310)	(15,087)
Interest Expense
Income From Continuing Operations Before Income Taxes	88,289	87,103
Income tax expense	32,797	32,409
Income From Continuing Operations	55,492	54,694
Discontinued Operations, net of tax
Income (loss) from discontinued operations	(1,126)	1,998
Loss on disposal of discontinued operations	(1,050)	0
Total Income (Loss) From Discontinued Operations	(2,176)	1,998
Net Income	53,316	56,692
Diluted Earnings Per Average Common Share
Continuing Operations (in dollars per share)	$ 0.76	$ 0.75
Discontinued operations (in dollars per share)	$ (0.03)	$ 0.03
Diluted Earnings Per Average Common Share (in dollars per share)	$ 0.73	$ 0.78
Basic Earnings Per Average Common Share
Continuing Operations (in dollars per share)	$ 0.76	$ 0.76
Discontinued operations (in dollars per share)	$ (0.03)	$ 0.03
Net Income (Loss) (in dollars per share)	$ 0.73	$ 0.79
Dividends Per Common Share (in dollars per share)	$ 0.15	$ 0.145
Diluted Average Common Shares Outstanding	73,045	72,288
Basic Average Common Shares Outstanding	72,629	72,143
Alabama Gas Corporation
Operating Revenues
Natural gas distribution	263,900	237,685
Operating Expenses
Cost of gas	128,114	95,442
Operations and maintenance	36,224	38,017
Depreciation, depletion and amortization	11,325	10,729
Income taxes
Current	25,217	25,921
Deferred	1,267	3,020
Taxes, other than income taxes	15,886	14,204
Total operating expenses	218,033	187,333
Operating Income	45,867	50,352
Other Income (Expense)
Interest expense	(3,965)	(4,030)
Allowance for funds used during construction	73	219
Other income	1,508	750
Other expense	(455)	(69)
Total other expense	1,126	900
Interest Expense
Interest on long-term debt	3,376	3,378
Other interest expense	589	652
Discontinued Operations, net of tax
Net Income	$ 43,028	$ 47,222

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

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Consolidated Condensed Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Current Assets
Allowance for doubtful accounts	$ 5,684	$ 5,694
Shareholders’ Equity
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	75,651,310	75,574,156
Treasury stock, shares	2,965,849	2,967,999
Alabama Gas Corporation
Current Assets
Allowance for doubtful accounts	$ 5,000	$ 5,000
Shareholders’ Equity
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	120,000	120,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	3,000,000	3,000,000
Common stock, shares issued	1,972,052	1,972,052

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Discontinued Operations Narrative (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended		3 Months Ended
	Oct. 31, 2013 Black Warrior Basin Properties Alabama	Dec. 31, 2013 Black Warrior Basin Properties Alabama Natural Gas Mcf	Mar. 31, 2014 North Louisiana and East Texas Natural Gas and Oil Properties	Dec. 31, 2013 North Louisiana and East Texas Natural Gas and Oil Properties	Sep. 30, 2013 North Louisiana and East Texas Natural Gas and Oil Properties	Jan. 31, 2014 North Louisiana and East Texas Natural Gas and Oil Properties	Dec. 31, 2013 North Louisiana and East Texas Natural Gas and Oil Properties Natural Gas Mcf	Dec. 31, 2013 North Louisiana and East Texas Natural Gas and Oil Properties Oil bbl
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from the sale of oil and gas property	$ 160
Gain on disposition of oil and gas property	35
Proved Developed Reserves (Volume)		97,000,000					23,000,000	91,000
Sales price						30.3
Impairment of oil and gas properties held-for-sale			$ 1.7	$ 5.2	$ 24.6

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Discontinued Operations (Tables)

3 Months Ended

Mar. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

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

	Three months ended
	March 31,
(in thousands, except per share data)	2014			2013
Oil and gas revenues	$	4,821		$	18,663
Pretax income (loss) from discontinued operations	$	(2,078	)	$	3,168
Income tax expense (benefit)	(952		)	1,170
Income (Loss) From Discontinued Operations	$	(1,126	)	$	1,998
Loss on disposal of discontinued operations	$	(1,667	)	$	—
Income tax benefit	(617		)	—
Loss on Disposal of Discontinued Operations	$	(1,050	)	$	—
Total Income (Loss) From Discontinued Operations	$	(2,176	)	$	1,998
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
Loss on Disposal of Discontinued Operations	(0.01		)	—
Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
Loss on Disposal of Discontinued Operations	(0.01		)	—
Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03

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

(in thousands)	March 31, 2014
	Black Warrior Basin			North Louisiana/East Texas			Total
Accounts receivable	$	—		$	1,670		$	1,670
Inventories	—			68			68
Other property, net	—			133			133
Total assets held-for-sale	—			1,871			1,871
Accounts payable	(2,172		)	(10		)	(2,182		)
Royalty payable	—			(1,221		)	(1,221		)
Other current liabilities	—			(7		)	(7		)
Total liabilities held-for-sale	(2,172		)	(1,238		)	(3,410		)
Total net held-for-sale properties	$	(2,172	)	$	633		$	(1,539	)

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Recently Issued Accounting Standards

3 Months Ended

Mar. 31, 2014

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This update defines a discontinued operation as a disposal of a component or a group of components that is disposed of or is classified as held-for-sale and represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendment is effective for all annual periods beginning on or after December 15, 2014, and interim periods within those annual periods. The Company is currently evaluating the impact of this ASU.

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Regulatory Matters (Details) (Alabama Gas Corporation, USD $)	0 Months Ended			3 Months Ended						0 Months Ended	12 Months Ended	0 Months Ended	3 Months Ended	12 Months Ended	0 Months Ended
	Jan. 02, 2014	Dec. 01, 2013	Dec. 01, 2012	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 APSC Approved Expension of ESR, November 1, 2010	Mar. 31, 2014 APSC Approved Expension of ESR, November 1, 2010 Self Insurance Costs	Mar. 31, 2014 APSC Approved Expension of ESR, November 1, 2010 Force Majeure Event Costs	Mar. 31, 2014 APSC Approved Expension of ESR, November 1, 2010 Force Majeure Events Costs	Jan. 02, 2014 APSC	Dec. 31, 2013 Minimum	Jan. 02, 2014 Minimum APSC	Mar. 31, 2014 Maximum	Dec. 31, 2013 Maximum	Jan. 02, 2014 Maximum APSC
Regulatory Matters [Line Items]
Approved return on equity												10.50%			10.95%
Adjusting point										10.80%
Allowed return on average common equity											13.15%			13.65%
Performance based adjustment on adjusting point	0.05%
Rate increases as percentage of prior year revenues													4.00%
Revenue reductions (increase) of rate adjustments	$ 8,500,000	$ (10,300,000)	$ (7,800,000)	$ 16,200,000	$ 2,400,000
Equity upon which a return will be permitted	56.50%
Approved increase	1.75%
Extraordinary operating and maintenance expenses minimum amount charged to Enhanced Stability Reserve							1,000,000	275,000	412,500
Large commercial and industrial customer budget minimum amount charged to Enhanced Stability Reserve						350,000
Enhanced Stability Reserve refund period				9 years
Enhanced Stability Reserve amortization period				5 years
Enhanced Stability Reserve, amortization expense				$ 660,000

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Subsequent Event

3 Months Ended

Mar. 31, 2014

Subsequent Events [Abstract]

Subsequent Event

SUBSEQUENT EVENTS

In April 2014, Energen signed a stock purchase agreement to sell Alagasco to The Laclede Group, Inc. (Laclede) for $1.6 billion, subject to closing adjustments, which includes an estimated $1.28 billion in cash and the assumption of $320 million in debt. This sale is expected to close during 2014. Energen plans to use cash proceeds from the sale to reduce long-term and short-term indebtedness.

Due to the sale of Alagasco discussed above, the Company has separated its qualified defined benefit plans and the postretirement health care and life insurance benefit plans into separate plans established for Energen and Alagasco. These separate plans will be remeasured effective April 30, 2014.

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

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

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Exploratory Costs

3 Months Ended

Mar. 31, 2014

Extractive Industries [Abstract]

Exploratory Costs

EXPLORATORY COSTS    

The Company capitalizes exploratory drilling costs until a determination is made that the well or project has either found proved reserves or is impaired. After an exploratory well has been drilled and found oil and natural gas reserves, a determination may be pending as to whether the oil and natural gas quantities can be classified as proved. In those circumstances, the Company continues to capitalize the drilling costs pending the determination of proved status if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Capitalized exploratory drilling costs are presented in oil and gas properties in the balance sheets. If the exploratory well is determined to be impaired, the impaired costs are charged to operations and maintenance expense. Other exploration costs, including geological and geophysical costs, are expensed as incurred.

The following table sets forth capitalized exploratory well costs and includes additions pending determination of proved reserves, reclassifications to proved reserves and costs charged to expense:

	Three months ended			Three months ended
(in thousands)	March 31, 2014			March 31, 2013
Capitalized exploratory well costs at beginning of period	$	57,600		$	79,791
Additions pending determination of proved reserves	164,842			95,861
Reclassifications due to determination of proved reserves	(112,474		)	(69,477		)
Capitalized exploratory well costs at end of period	$	109,968		$	106,175

The following table sets forth capitalized exploratory wells costs and includes amounts capitalized for a period greater than one year:

	Three months ended		Three months ended
(in thousands)	March 31, 2014		March 31, 2013
Exploratory wells in progress	$	62,280	$	21,676
Capitalized exploratory well costs capitalized for a period of one year or less	46,460		83,301
Capitalized exploratory well costs for a period greater than one year	1,228		1,198
Total capitalized exploratory well costs	$	109,968	$	106,175

At March 31, 2014, the Company had 45 gross exploratory wells either drilling or waiting on results from completion and testing. These wells are primarily located in the Permian Basin. The Company has one gross well capitalized greater than a year which is pending results from completion and testing. This well is currently waiting on facilities.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2014	May 01, 2014
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Entity Registrant Name	ENERGEN CORP
Entity Central Index Key	0000277595
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		72,781,704
Alabama Gas Corporation
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Entity Registrant Name	ALABAMA GAS CORP
Entity Central Index Key	0000003146
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,972,052

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Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2014

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES

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

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

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

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Segment Information

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

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

	Three months ended
	March 31,
(in thousands)	2014			2013
Operating revenues from continuing operations
Oil and gas operations	$	297,278		$	236,331
Natural gas distribution	263,900			237,685
Total	$	561,178		$	474,016
Operating income (loss) from continuing operations
Oil and gas operations	$	33,548		$	23,181
Natural gas distribution	72,351			79,293
Eliminations and corporate expenses	(1,300		)	(284		)
Total	$	104,599		$	102,190
Other income (expense) from continuing operations
Oil and gas operations	$	(13,819	)	$	(12,031	)
Natural gas distribution	(2,839		)	(3,130		)
Eliminations and other	348			74
Total	$	(16,310	)	$	(15,087	)
Income from continuing operations before income taxes	$	88,289		$	87,103

(in thousands)	March 31, 2014		December 31, 2013
Identifiable assets
Oil and gas operations	$	5,521,883	$	5,379,135
Natural gas distribution	1,209,375		1,193,413
Eliminations and other	49,132		49,664
Total	$	6,780,390	$	6,622,212

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Reconciliation of Earnings Per Share (EPS)

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Reconciliation of Earnings Per Share (EPS)

RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended					Three months ended
(in thousands, except per share amounts)	March 31, 2014					March 31, 2013
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	53,316	72,629	$	0.73	$	56,692	72,143	$	0.79
Effect of dilutive securities
Stock options			296					144
Non-vested restricted stock			44					1
Performance share awards			76					—
Diluted EPS	$	53,316	73,045	$	0.73	$	56,692	72,288	$	0.78

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

	Three months ended March 31,
(in thousands)	2014	2013
Stock options	111,554	988,087
Performance share awards	68,250	161,249

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Discontinued Operations

3 Months Ended

Mar. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

DISCONTINUED OPERATIONS

In March 2014, Energen Resources completed the sale on its North Louisiana/East Texas natural gas and oil properties for $30.3 million (subject to closing adjustments). The sale had an effective date of December 1, 2013, and the proceeds from the sale were used to repay short-term obligations. During the third quarter of 2013, Energen Resources classified these natural gas and oil properties as held-for-sale and reflected the associated operating results in discontinued operations. Energen Resources recognized a non-cash impairment writedown on these properties in the first quarter of 2014 of $1.7 million pre-tax to adjust the carrying amount of these properties to their fair value based on an estimate of the selling price of the properties. This non-cash impairment writedown is reflected in loss on disposal of discontinued operations in the three months ended March 31, 2014. Energen Resources also recognized non-cash impairment writedowns on these properties in the third and fourth quarters of 2013 of $24.6 million pre-tax and $5.2 million pre-tax, respectively. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment writedowns are classified as Level 3 fair value. At December 31, 2013, proved reserves associated with Energen’s North Louisiana/East Texas properties totaled 23 Bcf of natural gas and 91 MBbl of oil.

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

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

(in thousands)	March 31, 2014
	Black Warrior Basin			North Louisiana/East Texas			Total
Accounts receivable	$	—		$	1,670		$	1,670
Inventories	—			68			68
Other property, net	—			133			133
Total assets held-for-sale	—			1,871			1,871
Accounts payable	(2,172		)	(10		)	(2,182		)
Royalty payable	—			(1,221		)	(1,221		)
Other current liabilities	—			(7		)	(7		)
Total liabilities held-for-sale	(2,172		)	(1,238		)	(3,410		)
Total net held-for-sale properties	$	(2,172	)	$	633		$	(1,539	)

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

	Three months ended
	March 31,
(in thousands, except per share data)	2014			2013
Oil and gas revenues	$	4,821		$	18,663
Pretax income (loss) from discontinued operations	$	(2,078	)	$	3,168
Income tax expense (benefit)	(952		)	1,170
Income (Loss) From Discontinued Operations	$	(1,126	)	$	1,998
Loss on disposal of discontinued operations	$	(1,667	)	$	—
Income tax benefit	(617		)	—
Loss on Disposal of Discontinued Operations	$	(1,050	)	$	—
Total Income (Loss) From Discontinued Operations	$	(2,176	)	$	1,998
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
Loss on Disposal of Discontinued Operations	(0.01		)	—
Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$	(0.02	)	$	0.03
Loss on Disposal of Discontinued Operations	(0.01		)	—
Total Income (Loss) From Discontinued Operations	$	(0.03	)	$	0.03

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Asset Retirement Obligations

3 Months Ended

Mar. 31, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

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

During the three months ended March 31, 2014, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance as of December 31, 2013	$	108,533
Liabilities incurred	766
Liabilities settled	(413		)
Accretion expense	1,843
Balance as of March 31, 2014	$	110,729

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Alagasco recorded a conditional asset retirement obligation, on a discounted basis, of $27.8 million and $27.5 million to purge and cap its gas pipelines upon abandonment and to remediate other related obligations, as a regulatory liability as of March 31, 2014 and December 31, 2013, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $4.0 million and $4.6 million as of March 31, 2014 and December 31, 2013, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Under various agreements for third-party gathering, treatment, transportation or other services, Energen Resources is committed to deliver minimum production volumes or to pay certain costs in the event the minimum quantities are not delivered. These delivery commitments are approximately 6.4 million barrels of oil equivalent (MMBOE) through September 2017.

Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $150 million through September 2024. During the three months ended March 31, 2014 and 2013, Alagasco recognized approximately $13.4 million and $14.4 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 123 Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At March 31, 2014, the fixed price purchases under these guarantees had a maximum term outstanding through December 2014 with an aggregate purchase price and market value of $0.3 million.

Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings and the Company has accrued a provision for its estimated liability. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. The Company recognizes its liability for contingencies when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.

On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. Alagasco is cooperating with the National Transportation Safety Board which is investigating the incident. Alagasco has been named as a defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against Alagasco.

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

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

Under oversight of the Site Remediation Section of the Railroad Commission of Texas, the Company is currently in the process of cleanup and remediation of oil and gas wastes in nine reserve pits in Mitchell County, Texas. The Company estimates that the cleanup, remediation and related costs will approximate $2.1 million of which $1.9 million has been incurred and $0.2 million has been reserved.

During January 2014, Energen Resources responded to a General Notice and Information Request from the Environmental Protection Agency (EPA) regarding the Reef Environmental Site in Sylacauga, Talladega County, Alabama. The letter identifies Energen Resources as a potentially responsible party (PRP) under The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) for the cleanup of the Site. In 2008, Energen hired a third party to transport approximately 3,000 gallons of non-hazardous wastewater to Reef Environmental for wastewater treatment. Reef Environmental ceased operating its wastewater treatment system in 2010. Due to its one time use of Reef Environmental for a small volume of non-hazardous wastewater, Energen Resources has not accrued a liability for cleanup of the Site.

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, Alagasco’s share of the remediation costs will not materially affect the financial position of Alagasco. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the EPA, Alagasco and the current site owner.

In 2012, Alagasco responded to an EPA Request for Information Pursuant to Section 104 of CERCLA relating to the 35thAvenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by Alagasco and located in the vicinity of the 35thAvenue Superfund Site. In September 2013, Alagasco received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies Alagasco as a PRP under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. Alagasco has discussed its designation as a PRP further with the EPA, and Alagasco has requested additional information from the EPA regarding its designation as a PRP. Alagasco has also been approached by a law firm regarding entry into an agreement to toll the statute of limitations with potential plaintiffs related to purported damages allegedly incurred by such potential plaintiffs in connection with the 35th Avenue Superfund Site, and is considering whether to enter into such a tolling arrangement. Alagasco has not been provided information at this time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action, and therefore Alagasco has not agreed to undertake the proposed removal activities and no amount has been accrued as of March 31, 2014.

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

As a result of the audit, Energen Resources has been ordered by the ONRR to pay additional royalties on the specified U.S. federal leases in the amount of $142,000 and restructure its accounting for all federal leases in two counties in New Mexico from March 1, 2004, forward. The Company preliminarily estimates that application of the Order to all of the Company’s New Mexico federal leases would result in ONRR claims for up to approximately $23 million of additional royalties plus interest and penalties for the period from March 1, 2004, forward. The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of March 31, 2014.

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Discontinued Operations Balance Sheet and Income Statement (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Accounts receivable	$ 1,670
Inventories	68
Other property, net	133
Total assets held-for-sale	1,871
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]
Accounts payable	(2,182)
Royalty payable	(1,221)
Other current liabilities	(7)
Total liabilities held-for-sale	(3,410)
Total net held-for-sale properties	(1,539)
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Oil and gas revenues	4,821	18,663
Pretax income (loss) from discontinued operations	(2,078)	3,168
Income tax expense (benefit)	(952)	1,170
Income (Loss) From Discontinued Operations	(1,126)	1,998
Loss on disposal of discontinued operations	(1,667)	0
Income tax benefit	(617)	0
Loss on Disposal of Discontinued Operations	(1,050)	0
Total Income (Loss) From Discontinued Operations	(2,176)	1,998
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations (in dollars per share)	$ (0.02)	$ 0.03
Loss on Disposal of Discontinued Operations (in dollars per share)	$ (0.01)	$ 0.00
Total Income (Loss) From Discontinued Operations (in dollars per share)	$ (0.03)	$ 0.03
Basic Earnings Per Average Common Share
Income (Loss) from Discontinued Operations (in dollars per share)	$ (0.02)	$ 0.03
Loss on Disposal of Discontinued Operations (in dollars per share)	$ (0.01)	$ 0.00
Total Income (Loss) From Discontinued Operations (in dollars per share)	$ (0.03)	$ 0.03
Black Warrior Basin
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Accounts receivable	0
Inventories	0
Other property, net	0
Total assets held-for-sale	0
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]
Accounts payable	(2,172)
Royalty payable	0
Other current liabilities	0
Total liabilities held-for-sale	(2,172)
Total net held-for-sale properties	(2,172)
North Louisiana/East Texas
Assets of Disposal Group, Including Discontinued Operation [Abstract]
Accounts receivable	1,670
Inventories	68
Other property, net	133
Total assets held-for-sale	1,871
Liabilities of Disposal Group, Including Discontinued Operation [Abstract]
Accounts payable	(10)
Royalty payable	(1,221)
Other current liabilities	(7)
Total liabilities held-for-sale	(1,238)
Total net held-for-sale properties	$ 633

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Stock Compensation

3 Months Ended

Mar. 31, 2014

Share-based Compensation [Abstract]

Stock Compensation

STOCK COMPENSATION

Stock Incentive Plan

Stock Options: The Stock Incentive Plan provides for the grant of incentive stock options and non-qualified stock options to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option was granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 107,868 non-qualified option shares during the first quarter of 2014 with a grant-date fair value of $27.57.

Restricted Stock: Additionally, the Stock Incentive Plan provides for the grant of restricted stock units. In January 2014, the Company awarded 41,664 restricted stock units with a grant-date fair value of $70.68. These awards were valued based on the quoted market price of the Company’s common stock at the date of grant and have a three year vesting period.

Performance Share Awards: The Stock Incentive Plan also provides for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of an award period. The Stock Incentive Plan provides that payment of earned performance share awards be made in the form of Company common stock. Performance share awards are valued using the Monte Carlo model which uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. The Company granted 287 performance share awards during the first quarter of 2014 with a two year vesting period and a grant-date fair value of $118.99. The Company also granted 63,842 performance share awards during the first quarter of 2014 with a three year award period and a grant-date fair value of $93.13.

Stock Appreciation Rights Plan

The Energen Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company common stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 62,749 awards during the first quarter of 2014. These awards had a fair value of $35.04 as of March 31, 2014.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which are re-measured each reporting period and settle in cash at completion of the vesting period. During the first quarter of 2014, Energen Resources awarded 28,840 Petrotech units with a fair value of $79.18 as of March 31, 2014, none of which included a market condition. Also awarded were 36,920 Petrotech units which included a market condition and had a fair value of $115.94 as of March 31, 2014. These awards have a three year vesting period.

Stock Repurchase Program

During the three months ended March 31, 2014, the Company had non-cash purchases of approximately $0.3 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

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Employee Benefit Plans

3 Months Ended

Mar. 31, 2014

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

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

The components of net periodic benefit cost for the Company’s two defined benefit non-contributory pension plans and certain non-qualified supplemental pension plans were as follows:

	Three months ended March 31,
(in thousands)	2014			2013
Components of net periodic benefit cost:
Service cost	$	3,003		$	3,602
Interest cost	2,575			2,718
Expected long-term return on assets	(2,848		)	(3,713		)
Actuarial loss amortization	2,256			3,690
Prior service cost amortization	118			122
Settlement charge	7,262			144
Net periodic expense	$	12,366		$	6,563

The Company anticipates required contributions of approximately $0.5 million during 2014 to the qualified pension plans. The Company expects sufficient funding credits, as established under Internal Revenue Code Section 430(f), exist to meet the required funding. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $3.0 million to the qualified pension plans in January 2014. During 2014, the Company may make discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. For the three months ended March 31, 2014, the Company made benefit payments aggregating $33,000 to retirees from the non-qualified supplemental retirement plans and expects to make additional benefit payments of approximately $0.2 million through the remainder of 2014. In the first quarter of 2014, the Company incurred a settlement charge of $17.1 million for the payment of lump sums from the qualified defined benefit pension plans, of which $6.9 million was expensed and $10.2 million was recognized as a pension asset in regulatory assets at Alagasco. Also in the first quarter of 2014, the Company incurred a settlement charge of $0.4 million for the payment of lump sums from the non-qualified supplemental retirement plans. In the first quarter of 2013, the Company incurred a settlement charge of $0.5 million for the payment of lump sums from the non-qualified supplemental retirement plans, of which $0.1 million was expensed and $0.4 million was recognized as a pension asset in regulatory assets at Alagasco.

The components of net periodic benefit cost for the Company’s postretirement benefit plans were as follows:

	Three months ended March 31,
(in thousands)	2014			2013
Components of net periodic benefit cost:
Service cost	$	170		$	444
Interest cost	754			869
Expected long-term return on assets	(1,412		)	(1,242		)
Actuarial gain amortization	(520		)	—
Transition obligation amortization	27			324
Net periodic (income) expense	$	(981	)	$	395

There are no required contributions to the postretirement benefit plans during 2014.

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Financial Instruments

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Financial Instruments

FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, was approximately $1,421.2 million and $1,420.7 million and had a carrying value of $1,388.9 million and $1,403.9 million at March 31, 2014 and December 31, 2013, respectively. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, was approximately $263.5 million and $258.8 million and had a carrying value of $249.9 million at March 31, 2014 and December 31, 2013, respectively. The fair values are based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

At March 31, 2014, the Company had interest rate swap agreements with a notional of $200 million. The interest rate swaps exchange a variable interest rate for a fixed interest rate of 2.6675 percent. The fair value of the Company’s interest rate swap was a $1.6 million and a $1.8 million liability at March 31, 2014 and December 31, 2013, respectively, and is classified as Level 2 fair value liability. The fair value of the Company’s interest rate swap is recognized on a gross basis on the consolidated balance sheet.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At March 31, 2014 and December 31, 2013, Alagasco’s finance receivable totaled $10.5 million and $10.8 million, respectively. These finance receivables currently have an average balance of approximately $3,000 with terms of up to 84 months. Financing is available only to qualified customers who meet creditworthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to a third-party collection agency. Alagasco had finance receivables past due 90 days or more of $0.3 million and $0.4 million as of March 31, 2014 and December 31, 2013, respectively.

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

(in thousands)
Allowance for credit losses as of December 31, 2013	$	423
Provision	(124		)
Allowance for credit losses as of March 31, 2014	$	299

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Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

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

(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2013	$	12,178		$	(32,245	)	$	(20,067	)
Other comprehensive loss before reclassifications	(113		)	—			(113		)
Amounts reclassified from accumulated other comprehensive income (loss)	(2,224		)	5,613			3,389
Change in accumulated other comprehensive income (loss)	(2,337		)	5,613			3,276
Balance as of March 31, 2014	$	9,841		$	(26,632	)	$	(16,791	)

Reclassification out of Accumulated Other Comprehensive Income

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

	Three months ended			Three months ended
	March 31, 2014			March 31, 2013
(in thousands)	Amounts Reclassified						Line Item Where Presented
Gains and (losses) on cash flow hedges:
Derivative commodity instruments	$	4,054		$	17,290		Operating revenues
Interest rate swap	(446		)	(409		)	Interest expense
Total cash flow hedges	3,608			16,881
Income tax expense	(1,384		)	(6,427		)
Net of tax	2,224			10,454
Pension and postretirement plans:
Transition obligation	(10		)	(74		)	Operations and maintenance
Prior service cost	(74		)	(78		)	Operations and maintenance
Actuarial losses*	(1,290		)	(2,254		)	Operations and maintenance
Actuarial losses on settlement charges	(7,262		)	—			Operations and maintenance
Actuarial losses on settlement charges*	—			(375		)	Regulatory asset
Total pension and postretirement plans	(8,636		)	(2,781		)
Income tax benefit	3,023			973
Net of tax	(5,613		)	(1,808		)
Total reclassifications for the period	$	(3,389	)	$	8,646

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

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Commitments and Contingencies - New Mexico Audits (Details) (USD $)	3 Months Ended
	Mar. 31, 2014
Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Minimum loss contingency range of loss	$ 142,000
Maximum loss contingency range of possible loss	$ 23,000,000
Inestimable loss	The preliminary findings and subsequent Order (issued April 25, 2011) are contrary to deductions allowed under previous audits, retroactive in application and inconsistent with the Company’s understanding of industry practice. The Company is vigorously contesting the Order and has requested additional information from the ONRR and the Department to assist the Company in evaluating the ONRR Order and the Department’s findings. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of March 31, 2013.
New Mexico
Loss Contingencies [Line Items]
Number of counties ONRR has ordered to restructure accounting on federal leases	2

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Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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

(in thousands)	Cash Flow Hedges			Pension and Postretirement Plans			Total
Balance as of December 31, 2013	$	12,178		$	(32,245	)	$	(20,067	)
Other comprehensive loss before reclassifications	(113		)	—			(113		)
Amounts reclassified from accumulated other comprehensive income (loss)	(2,224		)	5,613			3,389
Change in accumulated other comprehensive income (loss)	(2,337		)	5,613			3,276
Balance as of March 31, 2014	$	9,841		$	(26,632	)	$	(16,791	)

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

	Three months ended			Three months ended
	March 31, 2014			March 31, 2013
(in thousands)	Amounts Reclassified						Line Item Where Presented
Gains and (losses) on cash flow hedges:
Derivative commodity instruments	$	4,054		$	17,290		Operating revenues
Interest rate swap	(446		)	(409		)	Interest expense
Total cash flow hedges	3,608			16,881
Income tax expense	(1,384		)	(6,427		)
Net of tax	2,224			10,454
Pension and postretirement plans:
Transition obligation	(10		)	(74		)	Operations and maintenance
Prior service cost	(74		)	(78		)	Operations and maintenance
Actuarial losses*	(1,290		)	(2,254		)	Operations and maintenance
Actuarial losses on settlement charges	(7,262		)	—			Operations and maintenance
Actuarial losses on settlement charges*	—			(375		)	Regulatory asset
Total pension and postretirement plans	(8,636		)	(2,781		)
Income tax benefit	3,023			973
Net of tax	(5,613		)	(1,808		)
Total reclassifications for the period	$	(3,389	)	$	8,646

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

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Derivative Commodity Instruments (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

The following tables detail the fair values of derivative commodity instruments on the balance sheets:

(in thousands)	March 31, 2014
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	17,522
Long-term asset derivative instruments	4,989
Total derivative assets	22,511
Accounts receivable	(14,165		)	*
Long-term asset derivative instruments	(2,351		)	*
Accounts payable	(52,602		)
Long-term liability derivative instruments	(802		)
Total derivative liabilities	(69,920		)
Total derivatives not designated	$	(47,409	)

(in thousands)	December 31, 2013
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	36,224
Long-term asset derivative instruments	7,992
Total derivative assets	44,216
Accounts receivable	(18,761		)	*
Long-term asset derivative instruments	(2,553		)	*
Accounts payable	(30,302		)
Total derivative liabilities	(51,616		)
Total derivatives not designated	$	(7,400	)

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

Schedule of Cash Flow Hedging Relationships on Financial Statements

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

(in thousands)	Location on Statements of Income	Three months ended March 31, 2014		Three months ended March 31, 2013
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $1 and ($16,424)	—	$	2	$	(26,798	)
Gain reclassified from accumulated other comprehensive income into income (effective portion)	Operating revenues	$	4,054	$	17,824
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	—	$	(534	)

Schedule of Derivatives Not Designated as Hedging Instruments on Income Statements

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

(in thousands)	Location on Statements of Income	Three months ended March 31, 2014			Three months ended March 31, 2013
Loss recognized in income on derivatives	Operating revenues	$	(57,446	)	$	(31,501	)

Schedule of Hedging Transactions

nergen Resources entered into the following transactions for the remainder of 2014 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2014	7,392	MBbl	$92.65 Bbl	NYMEX Swaps
2015	7,260	MBbl	$89.07 Bbl	NYMEX Swaps
Natural Gas
2014	7.9	Bcf	$4.55 Mcf	NYMEX Swaps
2014	23.5	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
2014	7.4	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	12.0	Bcf	$4.05 Mcf	Basin Specific Swaps - San Juan
Natural Gas Basis Differential
2014	4.6	Bcf	$(0.09) Mcf	San Juan Basis Swaps
2014	1.5	Bcf	$(0.17) Mcf	Permian Basis Swaps

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

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

	March 31, 2014
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(6,646	)	$	10,003		$	3,357
Noncurrent assets	1,192			1,446			2,638
Current liabilities	(42,531		)	(10,071		)	(52,602		)
Noncurrent liabilities	(802		)	—			(802		)
Net derivative asset (liability)	$	(48,787	)	$	1,378		$	(47,409	)

	December 31, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,658	)	$	19,121		$	17,463
Noncurrent assets	4,383			1,056			5,439
Current liabilities	(28,414		)	(1,888		)	(30,302		)
Net derivative asset (liability)	$	(25,689	)	$	18,289		$	(7,400	)

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

Schedule of Changes in Fair Value of Derivative Instruments Classified as Level 3

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

	Three months ended			Three months ended
(in thousands)	March 31, 2014			March 31, 2013
Balance at beginning of period	$	18,289		$	89,019
Realized gains (losses)	(3,019		)	27,107
Unrealized losses relating to instruments held at the reporting date*	(16,835		)	(63,482		)
Settlements during period	2,943			(26,185		)
Balance at end of period	$	1,378		$	26,459

Schedule of Fair Value Inputs, Derivatives, Quantitative Information

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

(in thousands)	Fair Value as of March 31, 2014			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2014	$	5,326		Discounted Cash Flow	Forward Basis	($0.06 - $0.09) Mcf
2015	$	(129	)	Discounted Cash Flow	Forward Basis	($0.14) Mcf
Natural Gas Basis - Permian
2014	$	(3,819	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.13) Mcf

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

Offsetting Assets and Liabilities

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

	March 31, 2014
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	22,511	$	(16,516	)	$	5,995	$	—	$	—	$	5,995
Derivative liabilities	$	69,920	$	(16,516	)	$	53,404	$	—	$	—	$	53,404

	December 31, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	44,215	$	(21,313	)	$	22,902	$	—	$	—	$	22,902
Derivative liabilities	$	51,615	$	(21,313	)	$	30,302	$	—	$	—	$	30,302

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Commitments and Contingencies - Commitments and Agreements (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended				3 Months Ended
	Sep. 30, 2013 Alabama Gas Corporation site	Mar. 31, 2014 Alabama Gas Corporation site	Mar. 31, 2014 Alabama Gas Corporation Wholly Owned Properties site	Mar. 31, 2014 Crude Oil and Natural Gas MBoe	Mar. 31, 2014 Natural Gas, Delivery and Storage Alabama Gas Corporation	Mar. 31, 2013 Natural Gas, Delivery and Storage Alabama Gas Corporation	Mar. 31, 2014 Natural Gas Alabama Gas Corporation Mcf
Long-term Purchase Commitment [Line Items]
Remaining contractual volume				6,400
Long-term purchase commitment					$ 150
Long-term purchase commitment, time period					September 2024		August 2020
Long-term commitments expense recognized in statement of operations					13.4	14.4
Long-term purchase commitment minimum quantity required							123,000,000
Recorded unconditional purchase obligation, time period							December 2014
Recorded unconditional purchase obligation							$ 0.3
Chain of title, manufactured gas plant sites		9	4
Chain of title, manufactured gas distribution sites		5	1
Number of sites with removal activities	50

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

[1] Includes $13.2 million and $12.4 million in mark-to-market losses for the three months ended March 31, 2014 and 2013, respectively.

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

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Derivative Commodity Instruments

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Commodity Instruments

DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas liquids and natural gas production. Such instruments may include over-the-counter (OTC) swaps and basis swaps typically executed with investment and commercial banks and energy-trading firms. Derivative transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with two of its active counterparties and in a net loss position with the remaining twelve at March 31, 2014. The largest counterparty net gain position at March 31, 2014, Macquarie Bank Limited, constituted approximately $3.0 million of Energen Resources’ total net loss on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

Prior to June 30, 2013, the Company utilized cash flow hedge accounting where applicable for its derivative transactions. The effective portion of the gain or loss on the derivative instrument was recognized in accumulated other comprehensive income as a component of shareholders’ equity and subsequently reclassified as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative’s change in fair value was required to be recognized in operating revenues immediately. All other derivative transactions not designated as cash flow hedge accounting are accounted for as mark-to-market transactions with gains or losses recognized in operating revenues in the period of change.

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

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

The following tables detail the fair values of derivative commodity instruments on the balance sheets:

(in thousands)	March 31, 2014
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	17,522
Long-term asset derivative instruments	4,989
Total derivative assets	22,511
Accounts receivable	(14,165		)	*
Long-term asset derivative instruments	(2,351		)	*
Accounts payable	(52,602		)
Long-term liability derivative instruments	(802		)
Total derivative liabilities	(69,920		)
Total derivatives not designated	$	(47,409	)

(in thousands)	December 31, 2013
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	$	36,224
Long-term asset derivative instruments	7,992
Total derivative assets	44,216
Accounts receivable	(18,761		)	*
Long-term asset derivative instruments	(2,553		)	*
Accounts payable	(30,302		)
Total derivative liabilities	(51,616		)
Total derivatives not designated	$	(7,400	)

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

The Company had a net $6.7 million and a net $8.2 million deferred tax liability included in current deferred income taxes on the balance sheets related to derivative items included in accumulated other comprehensive income as of March 31, 2014, and December 31, 2013, respectively.

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

(in thousands)	Location on Statements of Income	Three months ended March 31, 2014		Three months ended March 31, 2013
Net gain (loss) recognized in other comprehensive income on derivatives (effective portion), net of tax of $1 and ($16,424)	—	$	2	$	(26,798	)
Gain reclassified from accumulated other comprehensive income into income (effective portion)	Operating revenues	$	4,054	$	17,824
Loss recognized in income on derivatives (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	—	$	(534	)

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

(in thousands)	Location on Statements of Income	Three months ended March 31, 2014			Three months ended March 31, 2013
Loss recognized in income on derivatives	Operating revenues	$	(57,446	)	$	(31,501	)

As of March 31, 2014, $10.9 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. As of March 31, 2014, the Company had 7.4 million barrels (MMBbl) and 7.3 MMBbl of oil swaps which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. The Company had 44.9 billion cubic feet (Bcf) and 12.0 Bcf of natural gas and natural gas basis swaps which expire during 2014 and 2015, respectively, that are considered mark-to-market transactions. During 2013, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur due to certain properties being sold. This discontinuance of hedge accounting resulted in $2.6 million after-tax losses being recognized into operating revenues during the three months ended March 31, 2014.

As of March 31, 2014, Energen Resources entered into the following transactions for the remainder of 2014 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Oil
2014	7,392	MBbl	$92.65 Bbl	NYMEX Swaps
2015	7,260	MBbl	$89.07 Bbl	NYMEX Swaps
Natural Gas
2014	7.9	Bcf	$4.55 Mcf	NYMEX Swaps
2014	23.5	Bcf	$4.60 Mcf	Basin Specific Swaps - San Juan
2014	7.4	Bcf	$3.81 Mcf	Basin Specific Swaps - Permian
2015	12.0	Bcf	$4.05 Mcf	Basin Specific Swaps - San Juan
Natural Gas Basis Differential
2014	4.6	Bcf	$(0.09) Mcf	San Juan Basis Swaps
2014	1.5	Bcf	$(0.17) Mcf	Permian Basis Swaps

As of March 31, 2014, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2015.

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

	March 31, 2014
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(6,646	)	$	10,003		$	3,357
Noncurrent assets	1,192			1,446			2,638
Current liabilities	(42,531		)	(10,071		)	(52,602		)
Noncurrent liabilities	(802		)	—			(802		)
Net derivative asset (liability)	$	(48,787	)	$	1,378		$	(47,409	)

	December 31, 2013
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(1,658	)	$	19,121		$	17,463
Noncurrent assets	4,383			1,056			5,439
Current liabilities	(28,414		)	(1,888		)	(30,302		)
Net derivative asset (liability)	$	(25,689	)	$	18,289		$	(7,400	)

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

The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $18 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $18 million associated with open Level 3 mark-to-market derivative contracts. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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

	Three months ended			Three months ended
(in thousands)	March 31, 2014			March 31, 2013
Balance at beginning of period	$	18,289		$	89,019
Realized gains (losses)	(3,019		)	27,107
Unrealized losses relating to instruments held at the reporting date*	(16,835		)	(63,482		)
Settlements during period	2,943			(26,185		)
Balance at end of period	$	1,378		$	26,459

*Includes $13.2 million and $12.4 million in mark-to-market losses for the three months ended March 31, 2014 and 2013, respectively.

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

(in thousands)	Fair Value as of March 31, 2014			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2014	$	5,326		Discounted Cash Flow	Forward Basis	($0.06 - $0.09) Mcf
2015	$	(129	)	Discounted Cash Flow	Forward Basis	($0.14) Mcf
Natural Gas Basis - Permian
2014	$	(3,819	)	Discounted Cash Flow	Forward Basis	($0.12 - $0.13) Mcf

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

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

	March 31, 2014
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	22,511	$	(16,516	)	$	5,995	$	—	$	—	$	5,995
Derivative liabilities	$	69,920	$	(16,516	)	$	53,404	$	—	$	—	$	53,404

	December 31, 2013
								Gross Amounts Not Offset in the Balance Sheets
(in thousands)	Gross Amounts Recognized		Gross Amounts Offset in the Balance Sheets			Net Amount Presented in the Balance Sheets		Financial Instruments		Cash Collateral Received		Net Amount
Derivative assets	$	44,215	$	(21,313	)	$	22,902	$	—	$	—	$	22,902
Derivative liabilities	$	51,615	$	(21,313	)	$	30,302	$	—	$	—	$	30,302

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Reclassifications of Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Gains and (losses) on cash flow hedges:
Operating revenues from continuing operations	$ 561,178,000		$ 474,016,000
Interest expense	(17,640,000)		(16,752,000)
Income tax expense	(32,797,000)		(32,409,000)
Alabama Gas Corporation
Gains and (losses) on cash flow hedges:
Interest expense	(3,965,000)		(4,030,000)
Non-Qualified Supplemental Retirement Plans
Pension and postretirement plans:
Settlement charges	400,000		500,000
Settlement charges expensed			100,000
Non-Qualified Supplemental Retirement Plans | Alabama Gas Corporation
Pension and postretirement plans:
Settlements recognized as a pension asset			400,000
Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Net of tax	(3,389,000)		8,646,000
Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Total	3,608,000		16,881,000
Income tax expense	(1,384,000)		(6,427,000)
Net of tax	2,224,000		10,454,000
Pension and Postretirement Plans | Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Total	(8,636,000)		(2,781,000)
Income tax expense	3,023,000		973,000
Net of tax	(5,613,000)		(1,808,000)
Pension and postretirement plans:
Transition obligation	(10,000)		(74,000)
Prior service cost	(74,000)		(78,000)
Actuarial losses	(1,290,000)	[1]	(2,254,000)	[1]
Actuarial losses on settlement charges	(7,262,000)		0
Actuarial losses on settlement charges	0	[1]	(375,000)	[1]
Derivative commodity instruments | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Operating revenues from continuing operations	4,054,000		17,290,000
Interest rate swap | Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Gains and (losses) on cash flow hedges:
Interest expense	$ (446,000)		$ (409,000)

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

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Reconciliation of Earnings Per Share (EPS) (Tables)

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation

	Three months ended					Three months ended
(in thousands, except per share amounts)	March 31, 2014					March 31, 2013
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	53,316	72,629	$	0.73	$	56,692	72,143	$	0.79
Effect of dilutive securities
Stock options			296					144
Non-vested restricted stock			44					1
Performance share awards			76					—
Diluted EPS	$	53,316	73,045	$	0.73	$	56,692	72,288	$	0.78

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

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

	Three months ended March 31,
(in thousands)	2014	2013
Stock options	111,554	988,087
Performance share awards	68,250	161,249

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

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Acquisition and Dispositions of Properties

3 Months Ended

Mar. 31, 2014

Extractive Industries [Abstract]

Acquisition and Dispositions of Properties

ACQUISITION AND DISPOSITION OF PROPERTIES

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

During 2013, Energen also completed a total of approximately $31.3 million in various purchases of unproved leasehold properties.