10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

____________________________________________

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2012

OR

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

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

605 Richard Arrington Jr. Boulevard North

Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

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

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

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

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

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

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

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

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

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

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

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of July 30, 2012.

Energen Corporation	$0.01 par value	72,127,647 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 JUNE 30, 2012

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	28
	Selected Business Segment Data of Energen Corporation	38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	40
Item 4.	Controls and Procedures	41
PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 6.	Exhibits	42
SIGNATURES		43

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Six months ended
	June 30,						June 30,
(in thousands, except per share data)	2012			2011			2012			2011
Operating Revenues
Oil and gas operations	$	399,468		$	244,090		$	623,425		$	460,882
Natural gas distribution	70,887			86,309			265,374			355,881
Total operating revenues	470,355			330,399			888,799			816,763
Operating Expenses
Cost of gas	13,669			32,419			73,255			164,168
Operations and maintenance	112,713			103,232			223,274			207,014
Depreciation, depletion and amortization	101,991			65,629			196,525			126,757
Asset impairment	—			—			21,545			—
Taxes, other than income taxes	19,523			21,095			45,758			49,270
Accretion expense	1,861			1,689			3,674			3,338
Total operating expenses	249,757			224,064			564,031			550,547
Operating Income	220,598			106,335			324,768			266,216
Other Income (Expense)
Interest expense	(15,835		)	(9,463		)	(31,260		)	(18,867		)
Other income	659			779			2,217			2,009
Other expense	(582		)	(113		)	(221		)	(276		)
Total other expense	(15,758		)	(8,797		)	(29,264		)	(17,134		)
Income Before Income Taxes	204,840			97,538			295,504			249,082
Income tax expense	73,553			34,213			106,811			91,489
Net Income	$	131,287		$	63,325		$	188,693		$	157,593
Diluted Earnings Per Average Common Share	$	1.82		$	0.87		$	2.61		$	2.18
Basic Earnings Per Average Common Share	$	1.82		$	0.88		$	2.62		$	2.19
Dividends Per Common Share	$	0.140		$	0.135		$	0.280		$	0.270
Diluted Average Common Shares Outstanding	72,330			72,420			72,336			72,364
Basic Average Common Shares Outstanding	72,117			72,065			72,110			72,033

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

3

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended					Six months ended
	June 30,					June 30,
(in thousands)	2012			2011		2012			2011
Net Income	$	131,287		$	63,325	$	188,693		$	157,593
Other comprehensive income (loss):
Current period change in fair value of commodity derivative instruments, net of tax of $68,741, $30,307, $61,243 and ($29,067)	112,158			49,449		99,923			(47,425		)
Reclassification adjustment for commodity derivative instruments, net of tax of ($9,682), $2,474, ($9,379) and $217	(15,797		)	4,037		(15,303		)	354
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $25, $24, $50 and $48	47			44		93			89
Amortization of prior service cost, net of taxes of $30, $26, $59 and $52	55			48		110			97
Amortization of net loss, net of taxes of $413, $318, $826 and $635	766			591		1,533			1,179
Total pension and postretirement plans	868			683		1,736			1,365
Current period change in fair value of interest rate swap, net of tax of ($566) and ($830)	(1,051		)	—		(1,542		)	—
Reclassification adjustment for interest rate swap, net of tax of $144 and $280	267			—		520			—
Comprehensive Income	$	227,732		$	117,494	$	274,027		$	111,887

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

4

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	June 30, 2012		December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents	$	61,306	$	9,541
Accounts receivable, net of allowance for doubtful accounts of $6,848 at June 30, 2012, and $12,946 at December 31, 2011	247,095		231,925
Inventories
Storage gas inventory	35,650		44,047
Materials and supplies	36,089		26,420
Liquified natural gas in storage	3,689		3,545
Regulatory asset	60,485		57,143
Income tax receivable	2,942		7,343
Deferred income taxes	12,546		48,818
Prepayments and other	11,647		15,386
Total current assets	471,449		444,168
Property, Plant and Equipment
Oil and gas properties, successful efforts method	5,796,145		5,166,368
Less accumulated depreciation, depletion and amortization	1,576,618		1,382,526
Oil and gas properties, net	4,219,527		3,783,842
Utility plant	1,383,563		1,358,266
Less accumulated depreciation	557,137		544,838
Utility plant, net	826,426		813,428
Other property, net	23,914		23,506
Total property, plant and equipment, net	5,069,867		4,620,776
Other Assets
Regulatory asset	89,785		95,633
Long-term derivative instruments	103,273		31,056
Deferred charges and other	45,166		45,783
Total other assets	238,224		172,472
TOTAL ASSETS	$	5,779,540	$	5,237,416

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

5

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands, except share and per share data)	June 30, 2012			December 31, 2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	1,000		$	1,000
Notes payable to banks	310,000			15,000
Accounts payable	252,586			302,048
Accrued taxes	74,158			32,359
Customers' deposits	24,117			23,950
Amounts due customers	15,542			21,065
Accrued wages and benefits	22,799			35,258
Regulatory liability	28,497			58,279
Royalty payable	30,570			22,592
Other	30,292			32,328
Total current liabilities	789,561			543,879
Long-term debt	1,153,599			1,153,700
Deferred Credits and Other Liabilities
Asset retirement obligation	112,793			107,340
Pension and other postretirement liabilities	64,352			62,532
Regulatory liability	77,144			87,234
Long-term derivative instruments	1,624			34,663
Deferred income taxes	877,749			806,127
Other	10,174			9,778
Total deferred credits and other liabilities	1,143,836			1,107,674
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, 75,041,425 shares issued at June 30, 2012, and 75,007,412 shares issued at December 31, 2011	750			750
Premium on capital stock	489,584			482,918
Capital surplus	2,802			2,802
Retained earnings	2,269,385			2,100,885
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net	93,893			9,273
Pension and postretirement plans	(36,848		)	(38,584		)
Interest rate swap	(1,963		)	(941		)
Deferred compensation plan	3,632			3,511
Treasury stock, at cost; 3,037,234 shares at June 30, 2012, and 3,036,549 shares at December 31, 2011	(128,691		)	(128,451		)
Total shareholders' equity	2,692,544			2,432,163
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,779,540		$	5,237,416

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

6

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Six months ended June 30, (in thousands)	2012			2011
Operating Activities
Net income	$	188,693		$	157,593
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	196,525			126,757
Asset impairment	21,545			—
Accretion expense	3,674			3,338
Deferred income taxes	55,060			75,409
Bad debt expense	13			2,673
Exploratory expense	1,360			216
Change in derivative fair value	(80,221		)	(314		)
Gain on sale of assets	(167		)	(5,926		)
Other, net	11,543			8,543
Net change in:
Accounts receivable	62,635			43,066
Inventories	(1,416		)	(6,061		)
Accounts payable	(26,782		)	(20,434		)
Amounts due customers, including gas supply pass-through	(46,066		)	8,513
Income tax receivable	4,401			39,225
Pension and other postretirement benefit contributions	(4,116		)	(4,061		)
Other current assets and liabilities	39,186			12,589
Net cash provided by operating activities	425,867			441,126
Investing Activities
Additions to property, plant and equipment	(574,360		)	(378,640		)
Acquisitions, net of cash acquired	(76,894		)	(60,937		)
Proceeds from sale of assets	2,117			7,306
Other, net	(504		)	(413		)
Net cash used in investing activities	(649,641		)	(432,684		)
Financing Activities
Payment of dividends on common stock	(20,193		)	(19,458		)
Issuance of common stock	633			6,202
Payment of long-term debt	(123		)	(293		)
Net change in short-term debt	295,000			(3,000		)
Tax benefit on stock compensation	260			880
Other	(38		)	—
Net cash provided by (used in) financing activities	275,539			(15,669		)
Net change in cash and cash equivalents	51,765			(7,227		)
Cash and cash equivalents at beginning of period	9,541			22,659
Cash and Cash Equivalents at End of Period	$	61,306		$	15,432

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

7

CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Operating Revenues	$	70,887		$	86,309		$	265,374		$	355,881
Operating Expenses
Cost of gas	13,669			32,419			73,255			164,168
Operations and maintenance	36,169			36,212			70,235			73,534
Depreciation and amortization	10,533			9,846			20,979			19,626
Income taxes
Current	(2,631		)	(8,701		)	22,809			12,870
Deferred	2,969			6,562			6,167			12,962
Taxes, other than income taxes	6,068			6,669			17,897			22,331
Total operating expenses	66,777			83,007			211,342			305,491
Operating Income	4,110			3,302			54,032			50,390
Other Income (Expense)
Allowance for funds used during construction	131			234			265			392
Other income	340			374			1,138			993
Other expense	(296		)	(112		)	(170		)	(185		)
Total other income	175			496			1,233			1,200
Interest Charges
Interest on long-term debt	3,423			3,039			6,848			6,081
Other interest expense	536			497			1,173			1,072
Total interest charges	3,959			3,536			8,021			7,153
Net Income	$	326		$	262		$	47,244		$	44,437

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

8

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	June 30, 2012			December 31, 2011
ASSETS
Property, Plant and Equipment
Utility plant	$	1,383,563		$	1,358,266
Less accumulated depreciation	557,137			544,838
Utility plant, net	826,426			813,428
Other property, net	42			43
Current Assets
Cash and cash equivalents	15,927			7,817
Accounts receivable
Gas	37,855			96,812
Other	5,058			6,858
Affiliated companies	—			2,841
Allowance for doubtful accounts	(6,000		)	(12,100		)
Inventories
Storage gas inventory	35,650			44,047
Materials and supplies	4,962			4,183
Liquified natural gas in storage	3,689			3,545
Regulatory asset	60,485			57,143
Income tax receivable	1,904			9,762
Deferred income taxes	20,876			21,986
Prepayments and other	1,736			4,422
Total current assets	182,142			247,316
Other Assets
Regulatory asset	89,785			95,633
Deferred charges and other	9,833			10,380
Total other assets	99,618			106,013
TOTAL ASSETS	$	1,108,228		$	1,166,800

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

9

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands, except share data)	June 30, 2012		December 31, 2011
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 June 30, 2012 and December 31, 2011	20		20
Premium on capital stock	31,682		31,682
Capital surplus	2,802		2,802
Retained earnings	339,374		310,234
Total common shareholder's equity	373,878		344,738
Long-term debt	250,123		250,246
Total capitalization	624,001		594,984
Current Liabilities
Notes payable to banks	—		15,000
Accounts payable	59,678		110,552
Affiliated companies	14,304		—
Accrued taxes	36,065		26,861
Customers' deposits	24,117		23,950
Amounts due customers	15,542		21,065
Accrued wages and benefits	8,920		12,971
Regulatory liability	28,497		58,279
Other	10,256		9,250
Total current liabilities	197,379		277,928
Deferred Credits and Other Liabilities
Deferred income taxes	186,548		181,492
Pension and other postretirement liabilities	22,522		21,383
Regulatory liability	77,144		87,234
Long-term derivative instruments	—		3,070
Other	634		709
Total deferred credits and other liabilities	286,848		293,888
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,108,228	$	1,166,800

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

10

CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Six months ended June 30, (in thousands)	2012			2011
Operating Activities
Net income	$	47,244		$	44,437
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	20,979			19,626
Deferred income taxes	6,167			12,962
Bad debt expense	8			2,660
Other, net	432			1,620
Net change in:
Accounts receivable	30,036			31,975
Inventories	7,474			1,919
Accounts payable	(24,516		)	(17,284		)
Amounts due customers, including gas supply pass-through	(46,066		)	8,513
Income tax receivable	7,858			8,238
Pension and other postretirement benefit contributions	(1,363		)	(1,406		)
Other current assets and liabilities	9,008			4,491
Net cash provided by operating activities	57,261			117,751
Investing Activities
Additions to property, plant and equipment	(32,786		)	(34,386		)
Other, net	2,596			(1,545		)
Net cash used in investing activities	(30,190		)	(35,931		)
Financing Activities
Dividends	(18,104		)	(14,698		)
Payment of long-term debt	(123		)	(293		)
Other	(38		)	—
Net increases in advances from affiliates	14,304			—
Net change in short-term debt	(15,000		)	(70,000		)
Net cash used in financing activities	(18,961		)	(84,991		)
Net change in cash and cash equivalents	8,110			(3,171		)
Cash and cash equivalents at beginning of period	7,817			16,910
Cash and Cash Equivalents at End of Period	$	15,927		$	13,739

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, 2011, 2010 and 2009, included in the 2011 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.

2. REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period through December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology.

Alagasco's allowed range of return on average common equity is 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and six months ended June 30, 2012, Alagasco had a net $5.0 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the three months and six months ended June 30, 2011, Alagasco had a net $2.2 million pre-tax and a net $5.4 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $13.0 million annual increase and a $1.3 million annual decrease in revenues became effective December 1, 2011 and 2010, respectively.

RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate year ended September 30, 2011.

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

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

12

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

3. DERIVATIVE COMMODITY INSTRUMENTS

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

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which does not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with all of its active counterparties at June 30, 2012. The five largest counterparty net gain positions at June 30, 2012, Macquarie Bank Limited, J Aron & Company, Citibank, N.A., Shell Energy North America (US), L.P. and BP Corporation North America Inc. constituted approximately $33.1 million, $31.2 million, $23.9 million, $22.9 million and $19.8 million, respectively, of Energen Resources’ net gain on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of June 30, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

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

(in thousands)	June 30, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	102,499			$	—		$	102,499
Long-term asset derivative instruments	85,205				—			85,205
Total derivative assets	187,704				—			187,704
Accounts receivable	(13,592		)	*	—			(13,592		)
Long-term asset derivative instruments	(11,831		)	*	—			(11,831		)
Accounts payable	(3,940		)		—			(3,940		)
Long-term liability derivative instruments	(45		)		—			(45		)
Total derivative liabilities	(29,408		)		—			(29,408		)
Total derivatives designated	158,296				—			158,296
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,256				—			14,256
Long-term asset derivative instruments	29,899				—			29,899
Total derivative assets	44,155				—			44,155
Accounts payable	1,834			*	(30,574		)	(28,740		)
Total derivative liabilities	1,834				(30,574		)	(28,740		)
Total derivatives not designated	45,989				(30,574		)	15,415
Total derivatives	$	204,285			$	(30,574	)	$	173,711

(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

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

The Company had a net $57.5 million and a net $5.7 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of June 30, 2012, and December 31, 2011, respectively.

Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

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

(in thousands)	Location on Income Statement	Three months ended June 30, 2012		Three months ended June 30, 2011
Gain recognized in OCI on derivative (effective portion), net of tax of $68.7 million and $30.3 million	—	$	112,158	$	49,449
Gain (loss) reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	21,143	$	(5,770	)
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	4,336	$	(740	)

(in thousands)	Location on Income Statement	Six months ended June 30, 2012		Six months ended June 30, 2011
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of $61.2 million and ($29.1) million	—	$	99,923	$	(47,425	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	23,013	$	1,821
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	1,669	$	(2,391	)

The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:

(in thousands)	Location on Income Statement	Three months ended June 30, 2012		Three months ended June 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	123,448	$	(1	)

(in thousands)	Location on Income Statement	Six months ended June 30, 2012		Six months ended June 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	79,443	$	(1	)

As of June 30, 2012, $50.6 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of June 30, 2012, the Company had 3 billion, 5.6 billion and 4.6 billion cubic feet (Bcf) of natural gas hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 2.3 million, 6.1 million and 3.9 million barrels (MMBbl) of oil and oil basis hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 7.6 million and 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2012 and 2013, respectively, that did not meet the definition of a cash flow hedge but are

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considered by the Company to be economic hedges. During 2011, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur, which resulted in $0.1 million after-tax gain being recognized into operating revenues during the six months ended June 30, 2012.

Energen Resources entered into the following transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2012	6.7	Bcf	$4.62 Mcf	NYMEX Swaps
	18.1	Bcf	$4.15 Mcf	Basin Specific Swaps - San Juan
	3.0	Bcf	$2.89 Mcf	Basin Specific Swaps - Permian
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	9.1	Bcf	$4.65 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.79 Mcf	Basin Specific Swaps - Permian
Oil
2012	3,613	MBbl	$88.53 Bbl	NYMEX Swaps
2013	8,098	MBbl	$90.65 Bbl	NYMEX Swaps
2014	7,892	MBbl	$92.70 Bbl	NYMEX Swaps
Oil Basis Differential
2012	1,523	MBbl	$(2.95) Bbl	WTS/WTI Basis Swaps*
2013	2,768	MBbl	$(3.40) Bbl	WTS/WTI Basis Swaps*
Natural Gas Liquids
2012	30.0	MMGal	$0.98 Gal	Liquids Swaps
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

Alagasco entered into the following natural gas transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Description
2012	7.6	Bcf	NYMEX Swaps
2013	1.5	Bcf	NYMEX Swaps

As of June 30, 2012, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014, and March 31, 2013, respectively. Alagasco has not entered into any new cash flow derivative transactions on its gas supply since the summer of 2010. 

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The fair value hierarchy that prioritizes the inputs used to measure fair value is as follows:

Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2 - Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;

Level 3 - Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure.

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The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

Derivative commodity instruments are over-the-counter (OTC) derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties' valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.

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

	June 30, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	42,528		$	60,635		$	103,163
Noncurrent assets	59,468			43,805			103,273
Current liabilities	(32,185		)	(495		)	(32,680		)
Noncurrent liabilities	444			(489		)	(45		)
Net derivative asset	$	70,255		$	103,456		$	173,711

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

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

As of June 30, 2012, Alagasco had $30.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco had $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of June 30, 2012, and December 31, 2011.

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 $34 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $3.8 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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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)	June 30, 2012			June 30, 2011
Balance at beginning of period	$	104,923		$	16,927
Realized gains	4,858			1,204
Unrealized gains relating to instruments held at the reporting date	12,970			7,720
Settlements during period	(19,295		)	(12,405		)
Balance at end of period	$	103,456		$	13,446

	Six months ended			Six months ended
(in thousands)	June 30, 2012			June 30, 2011
Balance at beginning of period	$	65,801		$	42,755
Realized gains	4,858			1,204
Unrealized gains (losses) relating to instruments held at the reporting date	67,209			(3,554		)
Settlements during period	(34,412		)	(26,959		)
Balance at end of period	$	103,456		$	13,446

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 June 30, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2012	$	24,620		Discounted Cash Flow	Forward Basis	($0.13 - $0.16) Mcf
2013	$	36,216		Discounted Cash Flow	Forward Basis	($0.13 - $0.17) Mcf
2014	$	22,498		Discounted Cash Flow	Forward Basis	($0.13 - $0.16) Mcf
Natural Gas Basis - Permian
2012	$	(24	)	Discounted Cash Flow	Forward Basis	($0.11) Mcf
2013	$	(2	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(105	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
Oil Basis - WTS/WTI
2012	$	2,116		Discounted Cash Flow	Forward Basis	($4.34 - $4.57) Bbl
2013	$	(1,997	)	Discounted Cash Flow	Forward Basis	($2.65) Bbl
Natural Gas Liquids
2012	$	8,617		Discounted Cash Flow	Forward Price	$0.69 - $0.81 Gal
2013	$	11,517		Discounted Cash Flow	Forward Price	$0.72 - $0.78 Gal

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

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4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended					Three months ended
(in thousands, except per share amounts)	June 30, 2012					June 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	131,287	72,117	$	1.82	$	63,325	72,065	$	0.88
Effect of dilutive securities
Stock options			205					347
Non-vested restricted stock			8					8
Diluted EPS	$	131,287	72,330	$	1.82	$	63,325	72,420	$	0.87

	Six months ended					Six months ended
(in thousands, except per share amounts)	June 30, 2012					June 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	188,693	72,110	$	2.62	$	157,593	72,033	$	2.19
Effect of dilutive securities
Stock options			218					324
Non-vested restricted stock			8					7
Diluted EPS	$	188,693	72,336	$	2.61	$	157,593	72,364	$	2.18

For the three months and six months ended June 30, 2012, the Company had 856,843 and 849,583, respectively, options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months and six months ended June 30, 2011, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

5. SEGMENT INFORMATION

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

	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Operating revenues
Oil and gas operations	$	399,468		$	244,090		$	623,425		$	460,882
Natural gas distribution	70,887			86,309			265,374			355,881
Total	$	470,355		$	330,399		$	888,799		$	816,763
Operating income (loss)
Oil and gas operations	$	216,406		$	105,418		$	242,411		$	190,477
Natural gas distribution	4,448			1,163			83,008			76,222
Eliminations and corporate expenses	(256		)	(246		)	(651		)	(483		)
Total	$	220,598		$	106,335		$	324,768		$	266,216
Other income (expense)
Oil and gas operations	$	(12,004	)	$	(5,822	)	$	(22,562	)	$	(11,269	)
Natural gas distribution	(3,784		)	(3,040		)	(6,788		)	(5,953		)
Eliminations and other	30			65			86			88
Total	$	(15,758	)	$	(8,797	)	$	(29,264	)	$	(17,134	)
Income before income taxes	$	204,840		$	97,538		$	295,504		$	249,082

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(in thousands)	June 30, 2012		December 31, 2011
Identifiable assets
Oil and gas operations	$	4,596,172	$	4,046,242
Natural gas distribution	1,108,228		1,163,959
Eliminations and other	75,140		27,215
Total	$	5,779,540	$	5,237,416

6. STOCK COMPENSATION

Stock Incentive Plan

The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 371,040 non-qualified option shares during the first quarter of 2012 with a grant-date fair value of $18.79.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During the six months ended June 30, 2012, Energen Resources awarded 96,480, 3,768 and 40,822 Petrotech units with a three-year, two-year and 18 month vesting period, respectively. These awards have a fair value of $43.76, $44.30 and $44.58 per unit, respectively, as of June 30, 2012. In July 2012, Energen Resources awarded 5,869 Petrotech units with a three-year vesting period.

1997 Deferred Compensation Plan

During the three months and six months ended June 30, 2012, the Company had noncash purchases of approximately $35,000 and $118,000, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

7. EMPLOYEE BENEFIT PLANS

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	2,632		$	2,293		$	5,264		$	4,586
Interest cost	2,700			2,740			5,400			5,480
Expected long-term return on assets	(3,563		)	(3,868		)	(7,126		)	(7,736		)
Actuarial loss	2,099			1,609			4,198			3,218
Prior service cost amortization	129			124			259			248
Net periodic expense	$	3,997		$	2,898		$	7,995		$	5,796

The Companyanticipates required contributions of approximately $12.8 million during 2012 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. 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. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2012. For the three months and six months ending June 30, 2012, the Company made benefit payments aggregating $36,000 and $2.3 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $0.1 million through the remainder of 2012.

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During the second quarter of 2012, Congress passed the Moving Ahead for Progress in the 21st Century Act, which included pension funding stabilization provisions. The measure, which is designed to stabilize the discount rate used to determine funding requirements from the effects of interest rate volatility, is not expected to reduce the Company's pension plan cash contributions materially during 2012.

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	463		$	442		$	927		$	885
Interest cost	1,062			1,111			2,124			2,222
Expected long-term return on assets	(1,109		)	(1,104		)	(2,219		)	(2,209		)
Actuarial loss	9			—			18			—
Transition amortization	479			479			959			958
Net periodic expense	$	904		$	928		$	1,809		$	1,856

For the three months and six months ended June 30, 2012, the Company made contributions aggregating $0.9 million and $1.8 million, respectively, to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $1.8 million to the postretirement benefit plans through the remainder of 2012.

8. COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Certain of Alagasco's long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $79 million through September 2024. During the six months ending June 30, 2012 and 2011, Alagasco recognized approximately $25.9 million and $25.8 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 180 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 June 30, 2012, the fixed price purchases under these guarantees had a maximum term outstanding through March 2013 and an aggregate purchase price of $2.1 million with a market value of $1.8 million.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources' total resulting exposure could be as much as $26 million depending on the contractor's ability to remarket the drilling rig.

Income Taxes: The Company and Alagasco have on-going tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of the completion of various audits and the expiration of statute of limitations. Although the timing and outcome of these tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

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

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability. This provision was increased by $2.0 million during the six months ended June 30, 2012.

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

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns and is the subject of a recent inquiry discussed below. Also discussed below is the recent completion of a removal action at the Huntsville, Alabama manufactured gas plant site. An investigation of the sites does not indicate the present need for other remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the financial position of Alagasco.

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

In June 2009, Alagasco received a General Notice Letter from the EPA identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company and the current site owner entered into a Consent Order, and developed and completed during 2011 an action plan for the site. Alagasco has incurred costs associated with the site of approximately $4.9 million. As of June 30, 2012, the expected remaining costs are not expected to be material to the Company. Alagasco has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account of which a debit balance of $4.8 million was cleared as of September 30, 2011 and allocated, subject to APSC review guidelines, against the refundable negative salvage costs being refunded to customers.

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 $22 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 June 30, 2012.

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Capital Lease Obligations: During the first quarter of 2012, the Company entered into certain capital leases related to certain equipment. The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of June 30, 2012:

(in thousands)
2012	$	872
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,503
Less amount representing interest	115
Total present value of minimum lease payments	$	4,388

9. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen's long-term debt, including the current portion, approximates $1,234.6 million and has a carrying value of $1,155.1 million at June 30, 2012. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $281.5 million and has a carrying value of $250.1 million at June 30, 2012. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company's interest rate swap was a $3.0 million liability at June 30, 2012 and is classified as Level 1 fair value.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At June 30, 2012, and December 31, 2011, Alagasco’s finance receivable totaled $10.3 million and $10.5 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $431,000 as of June 30, 2012.

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

(in thousands)
Allowance for credit losses as of December 31, 2011	$	421
Provision	(2		)
Allowance for credit losses as of June 30, 2012	$	419

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10. REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	June 30, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	74,742	$	170	$	77,587
Accretion and depreciation for asset retirement obligation	—		14,584		—		13,981
Risk management activities	30,573		—		56,804		3,070
Asset removal costs, net	—		126		—		994
Gas supply adjustment	29,671		—		—		—
Other	71		333		169		1
Total regulatory assets	$	60,485	$	89,785	$	57,143	$	95,633
Regulatory liabilities:
RSE adjustment	$	4,586	$	—	$	2,931	$	—
Unbilled service margin	5,518		—		22,419		—
Gas supply adjustment	—		—		12,626		—
Refundable negative salvage	18,360		55,079		20,269		65,646
Asset retirement obligation	—		21,278		—		20,785
Other	33		787		34		803
Total regulatory liabilities	$	28,497	$	77,144	$	58,279	$	87,234

11. ASSET RETIREMENT OBLIGATIONS

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

During the six months ended June 30, 2012, 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 of ARO as of December 31, 2011	$	107,340
Liabilities incurred	2,122
Liabilities settled	(343		)
Accretion expense	3,674
Balance of ARO as of June 30, 2012	$	112,793

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco recorded a conditional asset retirement obligation, on a discounted basis of $21.3 million and $20.8 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of June 30, 2012, and December 31, 2011, respectively. The costs associated with asset retirement obligations are currently either being recovered in rates or are probable of recovery in future rates.

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. Regulatory assets for accumulated asset removal costs of $0.1 million and $1 million as of June 30, 2012 and December 31, 2011, respectively, are included as regulatory assets in noncurrent assets on the balance sheets. As of June 30, 2012 and December 31, 2011, the Company recognized $18.4 million and $20.3 million, respectively, of refundable negative salvage as regulatory liabilities in current liabilities on the balance sheet in response to the June 28, 2010, APSC order. As of June 30, 2012 and December 31, 2011, the Company recognized $55.1 million and $65.6 million,

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respectively, of refundable negative salvage as regulatory liabilities in deferred credit and other liabilities on the balance sheet in response to the June 28, 2010, APSC order.

12. ACQUISITION AND DISPOSITION OF OIL AND GAS PROPERTIES

During the first quarter of 2012, Energen Resources recognized a noncash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

On February 21, 2012, Energen Resources entered into a definitive agreement with BHP Billiton (BHP) to buy a 50 percent undivided interest in three existing wells in Reeves County, Texas, from Energen Resources for approximately $18 million. Following the purchase of the wells, BHP completed two of the wells and earned a 50 percent undivided interest in 4,829 net acres. The agreement also included the option for BHP to purchase from Energen Resources a 50 percent undivided interest in 51,720 net acres in the Permian Basin. On May 1, 2012, BHP elected not to exercise the option.

On February 14, 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million. This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.1 million barrels of oil equivalent (MMBOE). Of the proved reserves acquired, an estimated 81 percent are undeveloped. Approximately 64 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	67,615
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	65,581
Unproved leasehold properties	911
Accounts receivable	1,358
Accounts payable	(25		)
Asset retirement obligation	(210		)
Total identifiable net assets	$	67,615

Included in the Company’s consolidated results of operations for the six months ended June 30, 2012, were $5.3 million of operating revenues and $2.6 million in operating income resulting from the operation of the properties acquired above.

On December 27, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $56 million (subject to closing adjustments). This purchase had an effective date of July 1, 2011. Energen acquired total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

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The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

(in thousands)
Consideration given
Cash (net)	$	55,994
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	32,045
Unproved leasehold properties	23,686
Accounts receivable	680
Accounts payable	(244		)
Asset retirement obligation	(173		)
Total identifiable net assets	$	55,994

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

On November 16, 2011, Energen completed the purchase of certain liquids-rich properties in the Permian Basin for a cash purchase price of $162 million . This purchase had an effective date of August 1, 2011. Energen acquired total proved reserves of approximately 13.6 million MMBOE. Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	161,967
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,544
Unproved leasehold properties	7,883
Accounts receivable	3,070
Accounts payable	(388		)
Asset retirement obligation	(142		)
Total identifiable net assets	$	161,967

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

In July 2011, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $20 million. In April 2011, Energen completed the purchase of unproved leasehold properties for a cash purchase price of approximately $37 million covering an estimated 11,000 net acres in the Permian Basin.

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13. RECENTLY ISSUED ACCOUNTING STANDARDS

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

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This update requires entities to present the components of net income and other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. In December 2011, the FASB issued ASU No. 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05, which deferred the requirements to include reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The amendments in these updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of these updates has not had a material impact on the consolidated condensed financial statements or results of operations. The Company does not expect the portions of these updates that have been deferred to have a material impact on its consolidated condensed financial statements or results of operations.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirement in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments in this update result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. The amendments are effective during interim and annual periods beginning after December 15, 2011. This standard did not have a material impact on the consolidated condensed financial statements of the Company. The additional fair value disclosures are included in Note 3, Derivative Commodity Instruments.

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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 $131.3 million ($1.82 per diluted share) for the three months ended June 30, 2012 compared with net income of $63.3 million ($0.87 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended June 30, 2012, of $131.7 million as compared with $63.1 million in the same quarter in the previous year. This increase in net income was primarily the result of an after-tax $78.5 million non-cash mark-to-market gain on derivatives, significantly higher production volumes (approximately $44 million after-tax) and increased oil commodity prices (approximately $9 million after-tax). Negatively affecting net income was the impact of lower natural gas and natural gas liquids commodity prices (approximately $28 million after-tax), higher depreciation, depletion and amortization (DD&A) expense (approximately $23 million after-tax), increased lease operating expense excluding production taxes (approximately $5 million after-tax) and increased interest expense (approximately $4 million after-tax). Energen's natural gas utility, Alagasco, reported net income of $0.3 million in the first quarter of 2012 compared to net income of $0.3 million in the same period last year reflecting the utility’s ability to earn on a higher level of equity in support of Alagasco's investment in its distribution system and support facilities devoted to public service offset by the timing of rate recovery under Alagasco’s rate-setting mechanisms.

For the 2012 year-to-date, Energen's net income totaled $188.7 million ($2.61 per diluted share) compared to net income of $157.6 million ($2.18 per diluted share) for the same period in the prior year. Energen Resources generated net income for the six months ended June 30, 2012, of $141.2 million as compared with $112.8 million in the previous period. Increased production volumes (approximately $83 million), an after-tax $52.2 million non-cash mark-to-market gain on derivatives and higher oil commodity prices (approximately $21 million after-tax) partially offset by lower natural gas and natural gas liquids commodity prices (approximately $48 million after-tax), higher DD&A expense (approximately $45 million after-tax), a noncash impairment on certain natural gas properties in East Texas of approximately $13.4 million after-tax, increased lease operating expense excluding production taxes (approximately $11 million after-tax) and increased interest expense (approximately $7 million after-tax). Alagasco’s net income of $47.2 million in the current year-to-date compared to net income of $44.4 million in the same period in the previous year. This increase primarily reflects the utility’s ability to earn on a higher level of equity.

Oil and Gas Operations

Revenues from oil and gas operations rose 63.7 percent to $399.5 million and 35.3 percent to $623.4 million for the three months and six months ended June 30, 2012, respectively, primarily as a result of higher production volumes, significantly increased realized oil commodity prices and the non-cash mark-to-market gains on derivatives partially offset by decreased realized natural gas and natural gas liquids commodity prices. During the current quarter, revenue per unit of production for natural gas decreased 35.6 percent to $3.55 per thousand cubic feet (Mcf), while oil revenue per unit of production rose 8.2 percent to $85.70 per barrel. Natural gas liquids revenue per unit of production fell 21.1 percent to an average price of $0.75 per gallon. In the year-to-date, revenue per unit of production for natural gas decreased 31.9 percent to $3.75 per Mcf, oil revenue per unit of production increased 10.2 percent to $85.43 per barrel and natural gas liquids revenue per unit of production fell 12 percent to an average price of $0.81 per gallon. Revenues per unit of production for the current quarter and year-to-date reflect realized prices and derivative gains and losses including effects of designated cash flow hedges.

Production for the current quarter and year-to-date increased largely due to higher volumes related to increased field development in certain Permian Basin liquids-rich properties and increased volumes related to the 2011 acquisition of certain Permian Basin properties partially offset by normal production declines. Natural gas production in the second quarter rose 8.4 percent to 19.3 billion cubic feet (Bcf), oil volumes increased 46.2 percent to 2,195 thousand barrels (MBbl) and natural gas liquids production rose 23 percent to 27.8 million gallons (MMgal). For the year-to-date, natural gas production increased 9.3 percent to 38.4 Bcf, while oil volumes rose 44.8 percent to 4,148 MBbl. Natural gas liquids production increased 27.2 percent to 53.8 MMgal. Natural gas comprised approximately 54 percent of Energen Resources' production for the current quarter and year-to-date.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. Energen Resources recorded a pre-tax gain of $0.2 million in the second quarter of 2012 and year-to-date from the sale of various properties. Energen Resources recorded a pre-tax gain of $5.8 million in both the second quarter of 2011 and year-to-date primarily from the sale of certain properties in the Permian Basin.

Operations and maintenance (O&M) expense increased $9.5 million for the quarter and $19.4 million for the year-to-date. Lease operating expense (excluding production taxes) generally reflects year over year increases in the number of active wells resulting

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from Energen Resources' ongoing development, exploratory and acquisition activities. Lease operating expense (excluding production taxes) increased $8.1 million for the quarter largely due to increased water disposal costs (approximately $3.9 million), additional ad valorem taxes (approximately $1.4 million), higher marketing and transportation costs (approximately $0.9 million), the acquisitions of Permian Basin liquids-rich properties (approximately $0.9 million) and increased workover and repair expense (approximately $0.7 million). In the year-to-date, lease operating expense (excluding production taxes) increased $17.7 million primarily due to additional water disposal costs (approximately $4.8 million), increased workover and repair expense (approximately $3.1 million), higher marketing and transportation costs (approximately $2.3 million), increased ad valorem taxes (approximately $1.7 million), Permian Basin acquisitions (approximately $1.6 million), higher labor costs (approximately $1.6 million), and increased nonoperated expense (approximately $1.1 million). On a per unit basis, the average lease operating expense (excluding production taxes) for the current quarter was $9.69 per barrel of oil equivalent (BOE) as compared to $10.14 per BOE in the same period a year ago. For the six months ended June 30, 2012, the average lease operating expense (excluding production taxes) was $9.76 per BOE as compared to $10.04 per BOE in the previous period. Administrative expense increased $1.7 million for the three months ended June 30, 2012 largely due to higher labor costs (approximately $1.8 million). For the six months ended June 30, 2012, administrative expense rose $0.7 million primarily due to increased legal expenses (approximately $1.0 million), additional data service expense (approximately $0.6 million) and higher labor costs (approximately $0.5 million) partially offset by decreased costs from the Company’s performance-based compensation plans (approximately $1.5 million). Exploration expense fell $0.3 million in the second quarter of 2012 and rose $0.9 million year-to-date.

Energen Resources' DD&A expense for the quarter rose $35.7 million. For the year-to-date, DD&A expense increased $90 million which includes an impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of certain properties to their fair value based on expected future discounted cash flows. The average depletion rate for the current quarter was $14.90 per BOE as compared to $10.96 per BOE in the same period a year ago. For the six months ended June 30, 2012, the average depletion rate, excluding the asset impairment, was $14.68 per BOE as compared to $10.82 per BOE in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $21.9 million and $40.2 million, respectively, to the increase in DD&A expense, was largely due to higher rates resulting from the acquisition of liquids-rich properties and an increase in development costs. Higher production volumes contributed approximately $13.8 million and $28.1 million to the increase in DD&A expense for the quarter and year-to-date, respectively.

Energen Resources' expense for taxes other than income taxes was $1.0 million lower in the three months ended June 30, 2012 largely due to production-related taxes. Production-related taxes for the quarter decreased by approximately $4.0 million primarily due to lower net commodity market prices partially offset by higher natural gas, oil and natural gas liquid production volumes of approximately $3 million. Energen Resources' expense for taxes other than income taxes was $0.9 million higher in the six months ended June 30, 2012 largely due to production-related taxes. In the year-to-date, higher commodity production volumes contributed approximately $5.7 million to the increase in production-related taxes partially offset by a decrease of approximately $4.8 million primarily due to lower net commodity market prices. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues decreased $15.4 million for the quarter largely due to a decline in customer usage and lower gas costs combined with adjustments from the utility’s rate setting mechanisms. During the second quarter of 2012, Alagasco had a net $5.0 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the second quarter of 2011, Alagasco had a net $2.2 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the second quarter, weather that was 57.4 percent warmer than in the same quarter last year contributed to a 27.8 percent decrease in residential sales volumes and a 12.8 percent fall in commercial and industrial customer sales volumes. Transportation volumes increased 7.5 percent in period comparisons. Revenues for the year-to-date fell $90.5 million primarily due to a decline in customer usage and lower gas costs partially offset by adjustments from the utility’s rate setting mechanisms. During the year-to date 2012, Alagasco had a net $5.0 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. In the 2011 year-to-date, Alagasco had a net reduction in revenues of $5.4 million pre-tax to bring the return on average common equity to midpoint within the allowed range of return. Weather, for the current six months, that was 35.3 percent warmer compared with the same period in the prior year contributed to a 33.4 percent decrease in residential sales volumes and a 26.6 percent fall in commercial and industrial customer sales volumes. Transportation volumes decreased 1 percent in period comparisons. A significant decrease in gas purchase volumes along with decreased gas costs resulted in a 57.8 percent decrease in cost of gas for the quarter and a 55.4 percent decrease in cost of gas year-to-date. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco's rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco's tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

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O&M expense remained stable in the current quarter primarily due to lower bad debt expense (approximately $1.7 million) offset by increased insurance costs (approximately $0.6 million) and higher consulting and technology costs (approximately $0.6 million). In the six months ended June 30, 2012, O&M expense decreased 4.5 percent primarily due to lower bad debt expense (approximately $2.7 million) and decreased labor-related costs (approximately $1.5 million) partially offset by higher business development and marketing expense (approximately $0.6 million).

A 7 percent increase in depreciation expense in the current quarter and a 6.9 percent increase year-to-date was primarily due to the extension and replacement of the utility's distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company rose $6.4 million in the second quarter of 2012 and $12.4 million year-to-date largely due to the August 2011 issuance of $400 million of Senior Notes by Energen with an interest rate of 4.625 percent, the December 2011 issuance of $50 million of Senior Notes by Alagasco with an interest rate of 3.86 percent and the December 2011 issuance of $300 million of Senior Term Loans. The $300 million issuance includes $100 million with a floating rate of LIBOR plus 1.375 percent, currently 1.62 percent at June 30, 2012 and $200 million swapped to a fixed rate at 2.4175 percent. These increases were partially offset by decreased short-term borrowings. Income tax expense for the Company increased $39.3 million and $15.3 million in the current quarter and year-to-date, respectively, largely due to higher pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $425.9 million as compared to $441.1 million in the prior period. Net income increased during period comparisons primarily due to increased production volumes and higher realized oil commodity prices partially offset by lower realized natural gas and natural gas liquids commodity prices at Energen Resources. Deferred income taxes decreased in the current year due to the tax effect of reduced bonus depreciation in 2012. The Company’s working capital needs were also influenced by accrued taxes, commodity prices and the timing of payments. During the first quarter of 2011, the income tax receivable decreased approximately $39.8 million primarily from an income tax refund associated with the 2010 impact of bonus depreciation and the write-off of Alabama shale leasehold. Working capital needs at Alagasco were additionally affected by lower gas costs compared to the prior period.

The Company had a net outflow of cash from investing activities of $649.6 million for the six months ended June 30, 2012 primarily due to additions of property, plant and equipment of $651 million. Energen Resources incurred on a cash basis $618.5 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. In February 2012, Energen Resources completed the purchase of certain properties located in the Permian Basin for a cash price of approximately $68 million. Utility capital expenditures on a cash basis totaled $32.8 million year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities.

The Company provided net cash of $275.5 million from financing activities in the year-to-date primarily due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders.

Oil and Gas Operations

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2012, the Company expects its oil and gas capital spending to total approximately $1.1 billion, including $69 million for certain property acquisitions in the Permian Basin and $1 billion for existing properties, including exploration to date of $188 million. On an annual basis, the development and exploration expenditures cannot be reasonably segregated as drilling and development throughout the course of the year may change the classification of locations currently identified as exploratory. In February 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million (including the effects of closing adjustments). This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.1 MMBOE. Of the proved reserves acquired, an estimated 81 percent are undeveloped. Approximately 64 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions, except as disclosed above, are not included

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in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity.

Impairment

During the first quarter of 2012, Energen Resources recognized a noncash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

Natural Gas Distribution

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) and is allowed to earn a range of return on average common equity of 13.15 percent to 13.65 percent. RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Given existing economic conditions, Alagasco expects only modest growth in equity as annual dividends are typically paid by the utility.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million of refundable negative salvage costs through a one-time bill credit in July 2010. Refunds of negative salvage costs to customers through lower tariff rates were $12.5 million, $22.2 million and $2.7 million for the periods January through June 2012, January through December 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $18.4 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $55.1 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over a seven year period beginning January 1, 2013. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. On November 1, 2010, the APSC specifically approved adjustments to the total amount refundable to include items originally approved in the APSC's 1998 order establishing the ESR, extraordinary O&M expenses related to environmental response costs, and extraordinary O&M expenses related to self insurance costs that exceed $1 million per occurrence. As of the rate year ended September 30, 2011, an adjustment for environmental response costs of $4.8 million from the ESR was made to reduce the total refundable amount. The refunds as of March 2012 and the remaining amount refundable over the entire nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates.

Alagasco is a mature utility operating in a slow-growth service area. Over the last five years, Alagasco's customer count has declined at a rate of approximately 1 percent. While enhanced credit and collection processes implemented in 2011 to reduce bad debt expense combined with the impact of severe weather on April 27, 2011, including a number of deadly tornados causing significant damage to several communities in Alabama served by Alagasco, have resulted in a loss of customers, the number of active accounts as of June 30, 2012 had a small net increase as compared to June 30, 2011. To increase its customer base, the utility is capitalizing on opportunities to expand its distribution lines to areas with potential for economic growth and appliance conversions. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices and the underlying current and future economic conditions facing the utility's customer base. During the six months ended June 30, 2012, Alagasco reduced accounts receivable and the bad debt reserve by approximately $6.1 million related to certain aged receivables that have been currently transitioned to the utility's long-term collections.

Another aspect of growth is usage per customer. Throughout the country, customer use of natural gas has declined over the years in large part due to energy-efficiencies in home construction and appliances and conservation. Alagasco’s marketing and business development emphasis in this area is directed toward retention and increasing end-use applications by existing customers.

Alagasco maintains an investment in storage gas that is expected to average approximately $38 million in 2012 but will vary depending upon the price of natural gas. During 2012, Alagasco plans to invest an estimated $70 million in capital expenditures for the normal needs of its distribution and support systems and for technology-related projects designed to improve customer service. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities. Alagasco also may issue long-term debt periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.

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Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include over-the-counter (OTC) swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment and commercial banks and energy-trading firms. At June 30, 2012, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a gain position with all of its active counterparties at June 30, 2012. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which does not authorize speculative positions. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

Energen Resources entered into the following transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2012	6.7	Bcf	$4.62 Mcf	NYMEX Swaps
	0.4	Bcf *	$3.05 Mcf	NYMEX Swaps
	18.1	Bcf	$4.15 Mcf	Basin Specific Swaps - San Juan
	3.0	Bcf	$2.89 Mcf	Basin Specific Swaps - Permian
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	9.1	Bcf	$4.65 Mcf	NYMEX Swaps
	1.5	Bcf *	$3.95 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.79 Mcf	Basin Specific Swaps - Permian
	5.2	Bcf *	$3.83 Mcf	Basin Specific Swaps - Permian
Gas Basis Differential
2012	0.4	Bcf *	$(0.23) Mcf	San Juan Basis Swaps
Oil
2012	3,613	MBbl	$88.53 Bbl	NYMEX Swaps
2013	8,098	MBbl	$90.65 Bbl	NYMEX Swaps
	760	MBbl*	$94.08 Bbl	NYMEX Swaps
2014	7,892	MBbl	$92.70 Bbl	NYMEX Swaps
	780	MBbl*	$91.60 Bbl	NYMEX Swaps
Oil Basis Differential
2012	1,523	MBbl	$(2.95) Bbl	WTS/WTI Basis Swaps**
2013	2,768	MBbl	$(3.40) Bbl	WTS/WTI Basis Swaps**
	360	MBbl*	$(1.25) Bbl	WTI/WTI Basis Swaps***
Natural Gas Liquids
2012	30.0	MMGal	$0.98 Gal	Liquids Swaps
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
* Contract entered into subsequent to June 30, 2012
**WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing
***WTI - West Texas Intermediate/Midland, WTI - West Texas Intermediate/Cushing

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Alagasco entered into the following natural gas transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Description
2012	7.6	Bcf	NYMEX Swaps
2013	1.5	Bcf	NYMEX Swaps

Alagasco has not entered into any new cash flow derivative transactions on its gas supply since the summer of 2010. 

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:

	June 30, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	42,528		$	60,635		$	103,163
Noncurrent assets	59,468			43,805			103,273
Current liabilities	(32,185		)	(495		)	(32,680		)
Noncurrent liabilities	444			(489		)	(45		)
Net derivative asset (liability)	$	70,255		$	103,456		$	173,711

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

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

As of June 30, 2012, Alagasco had $30.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco has $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of June 30, 2012 and December 31, 2011.

Level 3 assets and liabilities as of June 30, 2012, represent approximately 2 percent of total assets and an immaterial amount of liabilities, respectively. 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 $34 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $3.8 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Title VII of the Dodd-Frank Act establishes federal oversight and regulation of the over-the-counter derivatives markets and participants in such markets and requires the Commodities Futures Trading Commission (CFTC) and the Securities and Exchange Commission (SEC)

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to promulgate implementing rules and regulations. The Dodd-Frank Act imposes certain margin, clearing and trade execution requirements. Under rules and regulations recently adopted by the CFTC and the SEC, the Company and Alagasco expect their derivatives transactions to qualify for an end-user exception which will exempt them from the Dodd-Frank Act margin and exchange clearing requirements. The Company and Alagasco will be subject to new and expanded documentation, record keeping and reporting requirements.

Stock Repurchases

Energen periodically considers stock repurchases as a capital investment. Energen may buy shares on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. The Company did not repurchase shares of common stock for this program during the six months ended June 30, 2012. The Company expects any future stock repurchases to be funded through internally generated cash flow or through the utilization of its credit facilities. During the three months and six months ended June 30, 2012, the Company had noncash purchases of approximately $35,000 and $0.1 million, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation plans. The Company utilized internally generated cash flows in payment of the related tax withholdings.

Credit Facilities and Working Capital

On October 29, 2010, Energen and Alagasco entered into an $850 million and a $150 million, respectively, three-year syndicated unsecured credit facility (syndicated credit facilities) with domestic and foreign lenders. Energen obligations under the $850 million syndicated credit facility are unconditionally guaranteed by Energen Resources. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of no more than 65 percent for each of the Company and Alagasco. The Company currently has available credit facilities as follows:

(in thousands)	Current Term	Energen		Alagasco		Total
Syndicated Credit Facility	10/29/2013	$	850,000	$	150,000	$	1,000,000
Bryant Bank	10/31/2012	-		9,000		9,000
BancorpSouth Bank	5/22/2013	-		10,000		10,000
Total		$	850,000	$	169,000	$	1,019,000

Energen and Alagasco rely upon internally generated cash flows supplemented by the syndicated credit facilities and the short-term credit facilities to fund working capital needs. The Company may also issue long-term debt and equity periodically to replace obligations under the credit facilities, enhance liquidity and provide for permanent financing.

Working capital requirements for Energen and Alagasco are influenced by short-term borrowings to finance recent acquisitions, the fair value of the Company's derivative financial instruments associated with future production, the recovery and pass-through of regulatory items and the seasonality of Alagasco's business. Energen's accounts receivable and accounts payable at June 30, 2012 include $103.2 million and $32.7 million, respectively, associated with its derivative financial instruments. Working capital at Alagasco reflects an expected pass-through to rate payers of $18.4 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates.

Dividends

Energen expects to pay annual cash dividends of $0.56 per share on the Company’s common stock in 2012. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

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Contractual Cash Obligations

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. Except as discussed below, there have been no material changes to the contractual cash obligations of the Company since December 31, 2011.

During the first quarter of 2012, the Company entered into certain capital leases related to certain equipment. The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of June 30, 2012:

(in thousands)
2012	$	872
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,503
Less amount representing interest	115
Total present value of minimum lease payments	$	4,388

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 $22 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 June 30, 2012.

Recent Accounting Standards Updates

See Note 13, 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 that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, production levels, reserve levels, energy markets, supply and demand for and the price of energy commodities including oil, gas and natural gas liquids, fluctuations in the weather, drilling risks, costs associated with compliance with environmental obligations, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, future business decisions, utility customer growth and retention and

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usage per customer, litigation results and other factors and uncertainties discussed elsewhere in this report and in the Company’s other public filings and press releases, all of which are difficult to predict. While it is not possible to predict or identify all the factors that could cause the Company’s actual results to differ materially from expected or historical results, the Company has identified certain risk factors which may affect the Company’s future business and financial performance.

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

Access to Credit Markets: 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 both lenders and the Company. 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 or limit availability of funds to the Company.

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

Alagasco’s Hedging: Similarly, although Alagasco has made use of cash flow derivative commodity instruments to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco's risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco's actual gas supply needs will generally meet or exceed the volumes subject to the cash flow derivative commodity instruments. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco's position. In addition, various existing and pending financial reform rules and regulations could have an adverse effect on the ability of Alagasco to use derivative instruments which could have a material adverse effect on our financial position, results of operations and cash flows.

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

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

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Energen Resources’ Production and Drilling:There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

Operations:Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. Further, the Company’s insurance retention levels are such that significant events could adversely affect Energen Resources’, Alagasco's and the Company's financial position, results of operations and cash flows. The location of 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. The occurrence of any of these events could adversely affect Alagasco's, Energen Resources’ and the Company's financial position, results of operations and cash flows.

Alagasco Service Territory: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.

Federal, State and Local Laws and Regulations: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.

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SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended				Six months ended
	June 30,				June 30,
(in thousands, except sales price data)	2012		2011		2012		2011
Oil and Gas Operations
Operating revenues
Natural gas	$	68,249	$	98,037	$	143,829	$	193,636
Oil	306,960		118,938		431,274		222,194
Natural gas liquids	23,692		21,482		47,404		39,015
Other	567		5,633		918		6,037
Total	$	399,468	$	244,090	$	623,425	$	460,882
Production volumes
Natural gas (MMcf)	19,278		17,778		38,370		35,112
Oil (MBbl)	2,195		1,501		4,148		2,865
Natural gas liquids (MMgal)	27.8		22.6		53.8		42.3
Total production volumes (MMcfe)	36,414		30,012		70,944		58,350
Total production volumes (MBOE)	6,069		5,002		11,824		9,725
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	3.54	$	5.51	$	3.75	$	5.51
Oil (barrel)	$	139.85	$	79.24	$	103.97	$	77.55
Natural gas liquids (gallon)	$	0.85	$	0.95	$	0.88	$	0.92
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf)	$	3.55	$	5.51	$	3.75	$	5.51
Oil (barrel)	$	85.70	$	79.24	$	85.43	$	77.55
Natural gas liquids (gallon)	$	0.75	$	0.95	$	0.81	$	0.92
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	2.19	$	4.18	$	2.43	$	4.10
Oil (barrel)	$	85.70	$	96.79	$	91.77	$	92.92
Natural gas liquids (gallon)	$	0.71	$	1.12	$	0.83	$	1.07
Other data
Lease operating expense (LOE)
LOE and other	$	58,779	$	50,712	$	115,391	$	97,657
Production taxes	13,205		14,192		27,367		26,475
Total	$	71,984	$	64,904	$	142,758	$	124,132
Depreciation, depletion and amortization	$	91,458	$	55,783	$	175,546	$	107,131
Asset impairment	$	—	$	—	$	21,545	$	—
Capital expenditures	$	293,909	$	259,533	$	634,876	$	399,856
Exploration expenditures	$	952	$	1,207	$	2,741	$	1,821
Operating income	$	216,406	$	105,418	$	242,411	$	190,477

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Natural Gas Distribution
Operating revenues
Residential	$	40,371		$	51,370		$	170,879		$	239,044
Commercial and industrial	20,442			23,393			67,198			90,299
Transportation	13,661			11,961			29,259			28,454
Other	(3,587		)	(415		)	(1,962		)	(1,916		)
Total	$	70,887		$	86,309		$	265,374		$	355,881
Gas delivery volumes (MMcf)
Residential	1,985			2,749			10,223			15,340
Commercial and industrial	1,449			1,662			4,891			6,662
Transportation	11,547			10,739			23,583			23,709
Total	14,981			15,150			38,697			45,711
Other data
Depreciation and amortization	$	10,533		$	9,846		$	20,979		$	19,626
Capital expenditures	$	18,030		$	22,297		$	32,973		$	35,837
Operating income	$	4,448		$	1,163		$	83,008		$	76,222

39

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its gas supply exposure. Such instruments may include over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by the Company. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. As of June 30, 2012, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014 and March 31, 2013, respectively

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 June 30, 2012, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at June 30, 2012 was 1.94 percent. The Company's interest rate exposure as of June 30, 2012, was minimal since approximately 91 percent of long-term debt obligations were at fixed rates.

40

ITEM 4. CONTROLS AND PROCEDURES

Energen Corporation

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

(b) Our chief executive officer and chief financial officer of Energen Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Alabama Gas Corporation

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

(b) Our chief executive officer and chief financial officer of Alabama Gas Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

41

PART II: OTHER INFORMATION

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

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs**
April 1, 2012 through April 30, 2012	—		—		—	8,992,700
May 1, 2012 through May 31, 2012	—		—		—	8,992,700
June 1, 2012 through June 30, 2012	806	*	$	43.05	—	8,992,700
Total	806		$	43.05	—	8,992,700

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

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

ITEM 6. EXHIBITS

31(a)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(b)	-	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(c)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(d)	-	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
32(a)	-	Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)	-	Section 906 Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350
101	-	The financial statements and notes thereto from Energen Corporation's Quarterly Report on Form 10-Q for the quarter
		ended June 30, 2012 are formatted in XBRL

42

SIGNATURES

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

		ENERGEN CORPORATION ALABAMA GAS CORPORATION
August 8, 2012	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
August 8, 2012	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
August 8, 2012	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
August 8, 2012	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

43

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.

August 8, 2012	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.

August 8, 2012	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.

August 8, 2012	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.

August 8, 2012	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 June 30, 2012, 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 August 8, 2012

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 June 30, 2012, 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 August 8, 2012

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.

XML

Reconciliation of Earnings Per Share (Details) - Earnings Per Share Reconciliation (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Earnings Per Share Reconciliation
Net Income, Basic EPS	$ 131,287	$ 63,325	$ 188,693	$ 157,593
Basic Shares Oustanding (in shares)	72,117	72,065	72,110	72,033
Earnings Per Share, Basic (dollars per share)	$ 1.82	$ 0.88	$ 2.62	$ 2.19
Effect of dilutive securities
Net Income, Diluted EPS	$ 131,287	$ 63,325	$ 188,693	$ 157,593
Diluted Shares Outstanding (in shares)	72,330	72,420	72,336	72,364
Earnings Per Share, Diluted (dollars per share)	$ 1.82	$ 0.87	$ 2.61	$ 2.18
Stock options
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements	205	347	218	324
Non-vested restricted stock
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements	8	8	8	7

XML

Financial Instruments (Details) (USD $)	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Jun. 30, 2012 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Jun. 30, 2012 Alabama Gas Corporation	Dec. 31, 2011 Alabama Gas Corporation	Jun. 30, 2012 Alabama Gas Corporation Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Jun. 30, 2012 Alabama Gas Corporation Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Dec. 31, 2011 Senior Loans [Member] Swap [Member]	Dec. 31, 2011 Senior Loans [Member] Swap [Member] Senior Term Loans, Due March 31, 2014 to November 29, 2016 [Member]	Dec. 31, 2011 Senior Loans [Member] Fair Value, Inputs, Level 1 [Member] Swap [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value		$ 1,234,600,000	$ 1,155,100,000			$ 281,500,000	$ 250,100,000
Debt Instrument, Face Amount									200,000,000
Debt Instrument, Interest Rate, Stated Percentage								2.4175%
Derivative Asset, Fair Value, Gross Liability										3,000,000
Financing Receivable				10,300,000	10,500,000
Financing Receivable, Recorded Investment, Average Balance 0 to 60 Days Past Due				3,000
Average Finance Receivable Term				up to 60 months
Financing Receivable, Recorded Investment, Equal to Greater than 90 Days Past Due				431,000
Financing Receivable, Allowance for Credit Losses [Roll Forward]
Allowance for credit losses, beginning balance	421,000
Provision	(2,000)
Allowance for credit losses, ending balance	$ 419,000

XML

Commitments and Contingencies (Details) - New Mexico Audits (Unfavorable Regulatory Action, USD $)	6 Months Ended
	Jun. 30, 2012
Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Minimum	$ 142,000
Loss Contingency, Range of Possible Loss, Maximum	$ 22,000,000
Loss Contingency, 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 June 30, 2012.

XML

Derivative Commodity Instruments - Commodity Contracts by Business Segment (Details) (USD $)	Jun. 30, 2012		Dec. 31, 2011
Derivative [Line Items]
Derivative, Fair Value, Net	$ 173,711,000		$ (88,820,000)
Deferred tax assets (liabilities), net	(57,500,000)		5,700,000
Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	204,285,000		(28,946,000)
Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative, Fair Value, Net	(30,574,000)		(59,874,000)
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	187,704,000		149,618,000
Derivative Liability, Fair Value, Net	(29,408,000)		(141,971,000)
Derivative, Fair Value, Net	158,296,000		7,647,000
Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	187,704,000		149,618,000
Derivative Liability, Fair Value, Net	(29,408,000)		(141,971,000)
Derivative, Fair Value, Net	158,296,000		7,647,000
Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Net	0		0
Derivative, Fair Value, Net	0		0
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	44,155,000		(12,255,000)
Derivative Liability, Fair Value, Gross Liability	(28,740,000)		(84,212,000)
Derivative, Fair Value, Net	15,415,000		(96,467,000)
Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	44,155,000		(12,255,000)
Derivative Liability, Fair Value, Gross Liability	1,834,000		(24,338,000)
Derivative, Fair Value, Net	45,989,000		(36,593,000)
Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Liability	(30,574,000)		(59,874,000)
Derivative, Fair Value, Net	(30,574,000)		(59,874,000)
Accounts Receivable [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	102,499,000		73,636,000
Derivative Liability, Fair Value, Gross Asset	(13,592,000)		(48,174,000)
Accounts Receivable [Member] | Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	102,499,000		73,636,000
Derivative Liability, Fair Value, Gross Asset	(13,592,000)	[1]	(48,174,000)	[1]
Accounts Receivable [Member] | Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Asset	0		0
Accounts Receivable [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	14,256,000		(3,670,000)
Accounts Receivable [Member] | Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	14,256,000	[1]	(3,670,000)	[1]
Accounts Receivable [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Other Assets [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	85,205,000		75,982,000
Derivative Liability, Fair Value, Gross Asset	(11,831,000)		(36,341,000)
Other Assets [Member] | Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	85,205,000		75,982,000
Derivative Liability, Fair Value, Gross Asset	(11,831,000)	[1]	(36,341,000)	[1]
Other Assets [Member] | Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Asset	0		0
Other Assets [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	29,899,000		(8,585,000)
Other Assets [Member] | Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	29,899,000	[1]	(8,585,000)	[1]
Other Assets [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Accounts Payable [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(3,940,000)		(37,070,000)
Accounts Payable [Member] | Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(3,940,000)		(37,070,000)
Accounts Payable [Member] | Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Accounts Payable [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(28,740,000)		(70,220,000)
Accounts Payable [Member] | Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,834,000		(13,416,000)
Accounts Payable [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(30,574,000)		(56,804,000)
Other Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(45,000)		(20,386,000)
Other Liabilities [Member] | Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(45,000)		(20,386,000)
Other Liabilities [Member] | Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Other Liabilities [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability			(13,992,000)
Other Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Oil and Gas Operations [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability			(10,922,000)
Other Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Distribution [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability			(3,070,000)
Cash Flow Hedging [Member] | Macquarie Bank Limited [Member]
Derivative [Line Items]
Derivative Assets	33,100,000
Cash Flow Hedging [Member] | J Aron and Company [Member]
Derivative [Line Items]
Derivative Assets	31,200,000
Cash Flow Hedging [Member] | Citibank, N.A. [Member]
Derivative [Line Items]
Derivative Assets	23,900,000
Cash Flow Hedging [Member] | Shell Energy North America US, L.P. [Member]
Derivative [Line Items]
Derivative Assets	22,900,000
Cash Flow Hedging [Member] | BP Corporation North America Inc. [Member]
Derivative [Line Items]
Derivative Assets	$ 19,800,000

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

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Operating revenues
Oil and gas operations	$	399,468		$	244,090		$	623,425		$	460,882
Natural gas distribution	70,887			86,309			265,374			355,881
Total	$	470,355		$	330,399		$	888,799		$	816,763
Operating income (loss)
Oil and gas operations	$	216,406		$	105,418		$	242,411		$	190,477
Natural gas distribution	4,448			1,163			83,008			76,222
Eliminations and corporate expenses	(256		)	(246		)	(651		)	(483		)
Total	$	220,598		$	106,335		$	324,768		$	266,216
Other income (expense)
Oil and gas operations	$	(12,004	)	$	(5,822	)	$	(22,562	)	$	(11,269	)
Natural gas distribution	(3,784		)	(3,040		)	(6,788		)	(5,953		)
Eliminations and other	30			65			86			88
Total	$	(15,758	)	$	(8,797	)	$	(29,264	)	$	(17,134	)
Income before income taxes	$	204,840		$	97,538		$	295,504		$	249,082

(in thousands)	June 30, 2012		December 31, 2011
Identifiable assets
Oil and gas operations	$	4,596,172	$	4,046,242
Natural gas distribution	1,108,228		1,163,959
Eliminations and other	75,140		27,215
Total	$	5,779,540	$	5,237,416

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning			$ 107,340
Liabilities incurred			2,122
Liabilities settled			(343)
Accretion expense	1,861	1,689	3,674	3,338
Balance of ARO, end	112,793		112,793
Regulatory Assets, Noncurrent	89,785		89,785		95,633
Regulatory Liability, Current	28,497		28,497		58,279
Regulatory Liability, Noncurrent	77,144		77,144		87,234
Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning					20,800
Balance of ARO, end	21,300		21,300		20,800
Regulatory Assets, Noncurrent	89,785		89,785		95,633
Regulatory Liability, Current	28,497		28,497		58,279
Regulatory Liability, Noncurrent	77,144		77,144		87,234
Asset removal costs | Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Assets, Noncurrent	100		100		1,000
Refundable negative salvage
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	18,400		18,400		20,300
Regulatory Liability, Noncurrent	55,100		55,100		65,600
Refundable negative salvage | Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	18,360		18,360		20,269
Regulatory Liability, Noncurrent	$ 55,079		$ 55,079		$ 65,646

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Stock Compensation (Details) (USD $)	3 Months Ended			6 Months Ended	3 Months Ended	6 Months Ended	1 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2012 Stock Incentive Plan	Mar. 31, 2012 Stock Incentive Plan	Jun. 30, 2012 Deferred Compensation Plan	Jun. 30, 2012 Deferred Compensation Plan	Jun. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, Three Years [Member]	Jun. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, Three Years [Member]	Jul. 31, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, Three Years [Member] Stock Compensation [Member]	Jun. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, Two Years [Member]	Jun. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, Two Years [Member]	Jun. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, 18 Months [Member]	Jun. 30, 2012 Petrotech Incentive Plan [Member] Restricted Stock Units (RSUs) [Member] Vesting Period, 18 Months [Member]
Share-based Compensation Arrangement by Share-based Payment Award
Award Vesting Period	3 years					3 years	3 years		2 years		18 months
Award Expiration Period	10 years
Grants in Period, Options, Fair Value		$ 18.79
Grants in Period, Options		371,040
Grants in Period, Other than Options						96,480	5,869		3,768		40,822
Grants in Period, Other than Options, Fair Value					$ 43.76			$ 44.30		$ 44.58
Noncash Payments for Repurchase of Common Stock			$ 35,000	$ 118,000

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Derivative Commodity Instruments - Derivative Instruments Change in Fair Value (Details) (Derivative Commodity Instruments, USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Derivative Commodity Instruments
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	$ 104,923	$ 16,927	$ 65,801	$ 42,755
Realized losses	4,858	1,204	4,858	1,204
Unrealized gains (losses) relating to instruments held at the reporting date	12,970	7,720	67,209	(3,554)
Settlements during period	(19,295)	(12,405)	(34,412)	(26,959)
Balance at end of period	$ 103,456	$ 13,446	$ 103,456	$ 13,446

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Commitments and Contingencies (Details) - Lease Obligations (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Jun. 30, 2012
Capital Leases, Future Minimum Payments Due [Abstract]
2012	$ 872
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,503
Less amount representing interest	115
Total present value of minimum lease payments	$ 4,388

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Regulatory Matters

6 Months Ended

Jun. 30, 2012

Regulated Operations [Abstract]

Regulatory Matters

REGULATORY MATTERS

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE’s current extension is for a seven-year period through December 31, 2014. RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to modify or discontinue the RSE methodology.

Alagasco's allowed range of return on average common equity is 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and six months ended June 30, 2012, Alagasco had a net $5.0 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the three months and six months ended June 30, 2011, Alagasco had a net $2.2 million pre-tax and a net $5.4 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $13.0 million annual increase and a $1.3 million annual decrease in revenues became effective December 1, 2011 and 2010, respectively.

RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range. Certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate year ended September 30, 2011.

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

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

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

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Employee Benefit Plans (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension Plans
Components of net periodic benefit cost:
Service cost	$ 2,632,000	$ 2,293,000	$ 5,264,000	$ 4,586,000
Interest cost	2,700,000	2,740,000	5,400,000	5,480,000
Expected long-term return on assets	(3,563,000)	(3,868,000)	(7,126,000)	(7,736,000)
Actuarial loss	2,099,000	1,609,000	4,198,000	3,218,000
Prior service cost amortization	129,000	124,000	259,000	248,000
Net periodic expense	3,997,000	2,898,000	7,995,000	5,796,000
Estimated Future Employer Contributions in Current Fiscal Year	12,800,000		12,800,000
Benefit Payments Made in Current Fiscal Year	36,000		2,300,000
Estimated Future Benefit Payments in Current Fiscal Year			100,000
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	463,000	442,000	927,000	885,000
Interest cost	1,062,000	1,111,000	2,124,000	2,222,000
Expected long-term return on assets	(1,109,000)	(1,104,000)	(2,219,000)	(2,209,000)
Actuarial loss	9,000	0	18,000	0
Transition amortization	479,000	479,000	959,000	958,000
Net periodic expense	904,000	928,000	1,809,000	1,856,000
Estimated Future Employer Contributions in Current Fiscal Year	1,800,000		1,800,000
Contributions by Employer in Current Fiscal Year	$ 900,000		$ 1,800,000

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Regulatory Assets and Liabilities (Tables) (Alabama Gas Corporation [Member])

6 Months Ended

Jun. 30, 2012

Alabama Gas Corporation [Member]

Regulatory Assets and Liabilities [Line Items]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

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

(in thousands)	June 30, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	74,742	$	170	$	77,587
Accretion and depreciation for asset retirement obligation	—		14,584		—		13,981
Risk management activities	30,573		—		56,804		3,070
Asset removal costs, net	—		126		—		994
Gas supply adjustment	29,671		—		—		—
Other	71		333		169		1
Total regulatory assets	$	60,485	$	89,785	$	57,143	$	95,633
Regulatory liabilities:
RSE adjustment	$	4,586	$	—	$	2,931	$	—
Unbilled service margin	5,518		—		22,419		—
Gas supply adjustment	—		—		12,626		—
Refundable negative salvage	18,360		55,079		20,269		65,646
Asset retirement obligation	—		21,278		—		20,785
Other	33		787		34		803
Total regulatory liabilities	$	28,497	$	77,144	$	58,279	$	87,234

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Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Allowance for Credit Losses on Financing Receivables [Table Text Block]

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

(in thousands)
Allowance for credit losses as of December 31, 2011	$	421
Provision	(2		)
Allowance for credit losses as of June 30, 2012	$	419

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Commitments and Contingencies (Details) - Commitments and Agreements (USD $) In Millions, unless otherwise specified	6 Months Ended		3 Months Ended	6 Months Ended
	Jun. 30, 2012 agreements	Jun. 30, 2012 Agreement Termination	Jun. 30, 2012 Pending or threatened legal proceedings	Jun. 30, 2012 Natural Gas Alabama Gas Corporation Bcf	Jun. 30, 2012 Natural Gas, Delivery and Storage Alabama Gas Corporation	Jun. 30, 2011 Natural Gas, Delivery and Storage Alabama Gas Corporation
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount					$ 79
Long-term Purchase Commitment, Time Period				August 2020	September 2024
Long Term Commitments Expense Recognized in Statements of Operations					25.9	25.8
Long-term Purchase Commitment, Minimum Quantity Required				180
Recorded Unconditional Purchase Obligation, Time Period				March 2013
Recorded Unconditional Purchase Obligation				2.1
Recorded Unconditional Purchase Obligation, Market Value				1.8
Drilling Plans, Agreement to Secure Drilling Rigs, Number of Agreements	3
Loss Contingency, Range of Possible Loss, Maximum		26
Loss Contingency Accrual, Carrying Value, Period Increase (Decrease)			$ 2.0

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

During the six months ended June 30, 2012, 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 of ARO as of December 31, 2011	$	107,340
Liabilities incurred	2,122
Liabilities settled	(343		)
Accretion expense	3,674
Balance of ARO as of June 30, 2012	$	112,793

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Acquisition and Dispositions of Oil and Gas Properties (Tables)

6 Months Ended

Jun. 30, 2012

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	67,615
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	65,581
Unproved leasehold properties	911
Accounts receivable	1,358
Accounts payable	(25		)
Asset retirement obligation	(210		)
Total identifiable net assets	$	67,615

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	161,967
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,544
Unproved leasehold properties	7,883
Accounts receivable	3,070
Accounts payable	(388		)
Asset retirement obligation	(142		)
Total identifiable net assets	$	161,967

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

(in thousands)
Consideration given
Cash (net)	$	55,994
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	32,045
Unproved leasehold properties	23,686
Accounts receivable	680
Accounts payable	(244		)
Asset retirement obligation	(173		)
Total identifiable net assets	$	55,994

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Basis of Presentation

6 Months Ended

Jun. 30, 2012

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, 2011, 2010 and 2009, included in the 2011 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.

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Regulatory Matters (Details) (Alabama Gas Corporation, USD $)	1 Months Ended		3 Months Ended		6 Months Ended		12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2011
Regulatory Matters [Line Items]
Enahanced Stability Reserve Extension Period					7 years
Revenue Impact of Rate Adjustments	$ 13,000,000	$ (1,300,000)	$ (5,000,000)	$ (2,200,000)	$ (5,000,000)	$ (5,400,000)
Adjustment Requirement Threshold for Return on Equity as Percentage of Operations and Maintenance Expenses to Consumer Price Index			0.75
Amortization Expense, Enhanced Stability Reserve, Annual Amount					660,000
Enahanced Stability Reserve Amortization Period							5 years
Enhanced Stability Reserve Refund Period							9 years
Return on Equity, Adjustment Requirements, Description					RSE limits the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense on an aggregate basis falls within a range of 0.75 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment is required. If the change in O&M expense on an aggregate basis exceeds the Index Range, three-quarters of the difference is returned to customers. To the extent the change is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. The O&M expense base for measurement purposes will be set at the prior year’s actual O&M expense amount unless the Company exceeds the top of the Index Range in two successive years, in which case the base for the following year will be set at the top of the Index Range.
Minimum
Regulatory Matters [Line Items]
Allowed Return on Average Common Equity			13.15%
Maximum
Regulatory Matters [Line Items]
Allowed Return on Average Common Equity			13.65%
Rate Increases as Percentage of Prior Year Revenues			4.00%
Limitation on Return on Equity as Percentage of Total Capitalization			55.00%
APSC Approved Expension of ESR, November 1, 2010
Regulatory Matters [Line Items]
Negative Revenue Variance, Large Commercial and Industrial Customer Budget, Minimum Amount, Charged to Enhanced Stability Reserve					350,000
APSC Approved Expension of ESR, November 1, 2010 | Force Majeure Event Costs
Regulatory Matters [Line Items]
Extraordinary Operating and Maintenance Expenses, Minimum Amount, Charged to Enhanced Stability Reserve					275,000
APSC Approved Expension of ESR, November 1, 2010 | Force Majeure Events Costs
Regulatory Matters [Line Items]
Extraordinary Operating and Maintenance Expenses, Minimum Amount, Charged to Enhanced Stability Reserve					412,500
APSC Approved Expension of ESR, November 1, 2010 | Environmental Response and Self Insurance Costs
Regulatory Matters [Line Items]
Extraordinary Operating and Maintenance Expenses, Minimum Amount, Charged to Enhanced Stability Reserve			$ 1,000,000

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Reconciliation of Earnings Per Share (Details) - Antidilutive Securities (Stock options)	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share (in options or shares)	856,843	849,583

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Consolidated Condensed Statements of Income (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Operating Revenues
Oil and gas operations	$ 399,468	$ 244,090	$ 623,425	$ 460,882
Natural gas distribution	70,887	86,309	265,374	355,881
Total operating revenues	470,355	330,399	888,799	816,763
Operating Expenses
Cost of gas	13,669	32,419	73,255	164,168
Operations and maintenance	112,713	103,232	223,274	207,014
Depreciation, depletion and amortization	101,991	65,629	196,525	126,757
Income taxes
Deferred			55,060	75,409
Asset impairment	0	0	21,545	0
Taxes, other than income taxes	19,523	21,095	45,758	49,270
Accretion expense	1,861	1,689	3,674	3,338
Total operating expenses	249,757	224,064	564,031	550,547
Operating Income	220,598	106,335	324,768	266,216
Other Income (Expense)
Interest expense	(15,835)	(9,463)	(31,260)	(18,867)
Other income	659	779	2,217	2,009
Other expense	(582)	(113)	(221)	(276)
Total other expense	(15,758)	(8,797)	(29,264)	(17,134)
Interest Charges
Income Before Income Taxes	204,840	97,538	295,504	249,082
Income tax expense	73,553	34,213	106,811	91,489
Net Income	131,287	63,325	188,693	157,593
Diluted Earnings Per Average Common Share	$ 1.82	$ 0.87	$ 2.61	$ 2.18
Basic Earnings Per Average Common Share	$ 1.82	$ 0.88	$ 2.62	$ 2.19
Dividends Per Common Share	$ 0.140	$ 0.135	$ 0.280	$ 0.270
Diluted Average Common Shares Outstanding	72,330	72,420	72,336	72,364
Basic Average Common Shares Outstanding	72,117	72,065	72,110	72,033
Alabama Gas Corporation
Operating Revenues
Natural gas distribution	70,887	86,309	265,374	355,881
Operating Expenses
Cost of gas	13,669	32,419	73,255	164,168
Operations and maintenance	36,169	36,212	70,235	73,534
Depreciation, depletion and amortization	10,533	9,846	20,979	19,626
Income taxes
Current	(2,631)	(8,701)	22,809	12,870
Deferred	2,969	6,562	6,167	12,962
Taxes, other than income taxes	6,068	6,669	17,897	22,331
Total operating expenses	66,777	83,007	211,342	305,491
Operating Income	4,110	3,302	54,032	50,390
Other Income (Expense)
Interest expense	(3,959)	(3,536)	(8,021)	(7,153)
Allowance for funds used during construction	131	234	265	392
Other income	340	374	1,138	993
Other expense	(296)	(112)	(170)	(185)
Total other expense	175	496	1,233	1,200
Interest Charges
Interest on long-term debt	3,423	3,039	6,848	6,081
Other interest expense	536	497	1,173	1,072
Net Income	$ 326	$ 262	$ 47,244	$ 44,437

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Commitments and Contingencies (Details) - Environmental Matters (Alabama Gas Corporation, USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Site Contingency [Line Items]
Environmental Remediation Estimated Cost	$ 4.9
Enhanced Stability Reserve [Member]
Site Contingency [Line Items]
Regulatory Assets	$ 4.8

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Consolidated Condensed Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Current Assets
Allowance for doubtful accounts	$ 7,744	$ 12,946
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	75,041,425	75,007,412
Treasury stock, shares	3,037,234	3,036,549
Alabama Gas Corporation
Current Assets
Allowance for doubtful accounts	$ 6,000	$ 12,100
Shareholders' Equity
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	120,000	120,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	3,000,000	3,000,000
Common stock, shares issued	1,972,052	1,972,052

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Derivative Commodity Instruments - Hedging Transactions (Details) (Cash Flow Hedging [Member])	Jun. 30, 2012 Bcf
Natural Gas [Member] | 2012 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	6.7
Average Contract Price, per Mcf	4.62
Natural Gas [Member] | 2012 | Basin Specific Swaps - San Juan [Member]
Derivative [Line Items]
Total Hedged Volumes	18.1
Average Contract Price, per Mcf	4.15
Natural Gas [Member] | 2012 | Basin Specific Swaps - Permain [Member]
Derivative [Line Items]
Total Hedged Volumes	3.0
Average Contract Price, per Mcf	2.89
Natural Gas [Member] | 2013 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	12.7
Average Contract Price, per Mcf	4.82
Natural Gas [Member] | 2013 | Basin Specific Swaps - San Juan [Member]
Derivative [Line Items]
Total Hedged Volumes	32.8
Average Contract Price, per Mcf	4.56
Natural Gas [Member] | 2013 | Basin Specific Swaps - Permain [Member]
Derivative [Line Items]
Total Hedged Volumes	4.6
Average Contract Price, per Mcf	3.45
Natural Gas [Member] | 2014 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	9.1
Average Contract Price, per Mcf	4.65
Natural Gas [Member] | 2014 | Basin Specific Swaps - San Juan [Member]
Derivative [Line Items]
Total Hedged Volumes	25.7
Average Contract Price, per Mcf	4.72
Natural Gas [Member] | 2014 | Basin Specific Swaps - Permain [Member]
Derivative [Line Items]
Total Hedged Volumes	4.6
Average Contract Price, per Mcf	3.79
Crude Oil [Member] | 2012 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	3,613
Average Contract Price, per Bbl	88.53
Crude Oil [Member] | 2012 | WTS/WTI Basis Swap [Member]
Derivative [Line Items]
Total Hedged Volumes	1,523
Average Contract Price, per Bbl	(2.95)
Crude Oil [Member] | 2013 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	8,098
Average Contract Price, per Bbl	90.65
Crude Oil [Member] | 2013 | WTS/WTI Basis Swap [Member]
Derivative [Line Items]
Total Hedged Volumes	2,768
Average Contract Price, per Bbl	(3.40)
Crude Oil [Member] | 2014 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	7,892
Average Contract Price, per Bbl	92.70
Natural Gas Liquids [Member] | 2012 | Liquids Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	30.0
Average Contract Price, Per Gal	0.98
Natural Gas Liquids [Member] | 2013 | Liquids Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	44.5
Average Contract Price, Per Gal	1.02
Alabama Gas Corporation [Member] | Natural Gas [Member] | 2012 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	7.6
Alabama Gas Corporation [Member] | Natural Gas [Member] | 2013 | NYMEX Swaps [Member]
Derivative [Line Items]
Total Hedged Volumes	1.5

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Recently Issued Accounting Standards Recently Issued Accounting Standards (Policies)

6 Months Ended

Jun. 30, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

New Accounting Pronouncements, Policy [Policy Text Block]

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

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This update requires entities to present the components of net income and other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. In December 2011, the FASB issued ASU No. 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05, which deferred the requirements to include reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The amendments in these updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of these updates has not had a material impact on the consolidated condensed financial statements or results of operations. The Company does not expect the portions of these updates that have been deferred to have a material impact on its consolidated condensed financial statements or results of operations.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirement in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments in this update result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. The amendments are effective during interim and annual periods beginning after December 15, 2011. This standard did not have a material impact on the consolidated condensed financial statements of the Company. The additional fair value disclosures are included in Note 3, Derivative Commodity Instruments.

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Derivative Commodity Instruments - Derivatives Measured at Fair Value on a Recurring Basis (Details) (USD $)									3 Months Ended
	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2011 Fair Value, Measurements, Recurring [Member]	Jun. 30, 2012 Level 2 Fair Value, Measurements, Recurring [Member]		Dec. 31, 2011 Level 2 Fair Value, Measurements, Recurring [Member]		Jun. 30, 2012 Level 3	Jun. 30, 2012 Level 3 Fair Value, Measurements, Recurring [Member]		Dec. 31, 2011 Level 3 Fair Value, Measurements, Recurring [Member]		Jun. 30, 2012 Alabama Gas Corporation [Member]	Dec. 31, 2011 Alabama Gas Corporation [Member]	Jun. 30, 2012 Alabama Gas Corporation [Member] Level 2 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2011 Alabama Gas Corporation [Member] Level 2 Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Current assets			$ 103,163,000	$ 21,792,000	$ 42,528,000	[1]	$ (14,843,000)	[1]		$ 60,635,000	[1]	$ 36,635,000	[1]
Noncurrent assets	103,273,000	31,056,000	103,273,000	31,056,000	59,468,000	[1]	(8,382,000)	[1]		43,805,000	[1]	39,438,000	[1]
Current liabilities			(32,680,000)	(107,290,000)	(32,185,000)	[1]	(98,468,000)	[1]		(495,000)	[1]	(8,822,000)	[1]			(30,600,000)	(56,800,000)
Noncurrent liabilities	(1,624,000)	(34,663,000)	(45,000)	(34,378,000)	444,000	[1]	(32,928,000)	[1]		(489,000)	[1]	(1,450,000)	[1]	0	(3,070,000)		(3,100,000)
Net derivative asset (liability)			173,711,000	(88,820,000)	70,255,000	[1]	(154,621,000)	[1]		103,456,000	[1]	65,801,000	[1]
Impact on fair value of a 10 percent increase or decrease in commodity prices									34,000,000
Impact on results of operations of a 10 percent increase or decrease in commodity prices									$ 3,800,000

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

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Reconciliation of Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2012

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation

	Three months ended					Three months ended
(in thousands, except per share amounts)	June 30, 2012					June 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	131,287	72,117	$	1.82	$	63,325	72,065	$	0.88
Effect of dilutive securities
Stock options			205					347
Non-vested restricted stock			8					8
Diluted EPS	$	131,287	72,330	$	1.82	$	63,325	72,420	$	0.87

	Six months ended					Six months ended
(in thousands, except per share amounts)	June 30, 2012					June 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	188,693	72,110	$	2.62	$	157,593	72,033	$	2.19
Effect of dilutive securities
Stock options			218					324
Non-vested restricted stock			8					7
Diluted EPS	$	188,693	72,336	$	2.61	$	157,593	72,364	$	2.18

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Consolidated Condensed Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Operating Activities
Net Income	$ 188,693	$ 157,593
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	196,525	126,757
Asset impairment	21,545	0
Accretion expense	3,674	3,338
Deferred income taxes	55,060	75,409
Bad debt expense	13	2,673
Exploratory expense	1,360	216
Change in derivative fair value	(80,221)	(314)
Gain on sale of assets	(167)	(5,926)
Other, net	11,543	8,543
Net change in:
Accounts receivable	62,635	43,066
Inventories	(1,416)	(6,061)
Accounts payable	(26,782)	(20,434)
Amounts due customers including gas supply pass-through	(46,066)	8,513
Income tax receivable	4,401	39,225
Pension and other postretirement benefit contributions	(4,116)	(4,061)
Other current assets and liabilities	39,186	12,589
Net cash provided by operating activities	425,867	441,126
Investing Activities
Additions to property, plant and equipment	(574,360)	(378,640)
Acquisitions, net of cash acquired	(76,894)	(60,937)
Proceeds from sale of assets	2,117	7,306
Other, net	(504)	(413)
Net cash used in investing activities	(649,641)	(432,684)
Financing Activities
Payment of dividends on common stock	(20,193)	(19,458)
Issuance of common stock	633	6,202
Payment of long-term debt	(123)	(293)
Other		0
Net change in short-term debt	295,000	(3,000)
Tax benefit on stock compensation	260	880
Other	(38)	0
Net cash provided by (used in) financing activities	275,539	(15,669)
Net change in cash and cash equivalents	51,765	(7,227)
Cash and cash equivalents at beginning of period	9,541	22,659
Cash and Cash Equivalents at End of Period	61,306	15,432
Alabama Gas Corporation
Operating Activities
Net Income	47,244	44,437
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	20,979	19,626
Deferred income taxes	6,167	12,962
Bad debt expense	8	2,660
Other, net	432	1,620
Net change in:
Accounts receivable	30,036	31,975
Inventories	7,474	1,919
Accounts payable	(24,516)	(17,284)
Amounts due customers including gas supply pass-through	(46,066)	8,513
Income tax receivable	7,858	8,238
Pension and other postretirement benefit contributions	(1,363)	(1,406)
Other current assets and liabilities	9,008	4,491
Net cash provided by operating activities	57,261	117,751
Investing Activities
Additions to property, plant and equipment	(32,786)	(34,386)
Other, net	2,596	(1,545)
Net cash used in investing activities	(30,190)	(35,931)
Financing Activities
Payment of dividends on common stock	(18,104)	(14,698)
Payment of long-term debt	(123)	(293)
Other	(38)
Net increases in advances from affiliates	14,304	0
Net change in short-term debt	(15,000)	(70,000)
Net cash provided by (used in) financing activities	(18,961)	(84,991)
Net change in cash and cash equivalents	8,110	(3,171)
Cash and cash equivalents at beginning of period	7,817	16,910
Cash and Cash Equivalents at End of Period	$ 15,927	$ 13,739

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Consolidated Condensed Statements of Comprehensive Income of Energen Corporation (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Net Income	$ 131,287	$ 63,325	$ 188,693	$ 157,593
Other Comprehensive Income (Loss):
Current period change in fair value of commodity derivative instruments, net of tax of $68,741, $30,307, $61,243 and ($29,067)	112,158	49,449	99,923	(47,425)
Pension and postretirement plans:
Amortization of net obligation at transition, net of taxes of $25, $24, $50 and $48	47	44	93	89
Amortization of prior service cost, net of taxes of $30, $26, $59 and $52	55	48	110	97
Amortization of net loss, net of taxes of $413, $318, $826 and $635,	766	591	1,533	1,179
Total pension and postretirement plans	868	683	1,736	1,365
Current period change in fair value of interest rate swap, net of tax ($566) and ($830)	(1,051)	0	(1,542)	0
Comprehensive Income (Loss)	227,732	117,494	274,027	111,887
Commodity Contract [Member]
Other Comprehensive Income (Loss):
Reclassification adjustment for derivative instruments, net of tax	(15,797)	4,037	(15,303)	354
Interest Rate Swap [Member]
Other Comprehensive Income (Loss):
Reclassification adjustment for derivative instruments, net of tax	$ 267	$ 0	$ 520	$ 0

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Regulatory Assets and Liabilities

6 Months Ended

Jun. 30, 2012

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)	June 30, 2012				December 31, 2011
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	74,742	$	170	$	77,587
Accretion and depreciation for asset retirement obligation	—		14,584		—		13,981
Risk management activities	30,573		—		56,804		3,070
Asset removal costs, net	—		126		—		994
Gas supply adjustment	29,671		—		—		—
Other	71		333		169		1
Total regulatory assets	$	60,485	$	89,785	$	57,143	$	95,633
Regulatory liabilities:
RSE adjustment	$	4,586	$	—	$	2,931	$	—
Unbilled service margin	5,518		—		22,419		—
Gas supply adjustment	—		—		12,626		—
Refundable negative salvage	18,360		55,079		20,269		65,646
Asset retirement obligation	—		21,278		—		20,785
Other	33		787		34		803
Total regulatory liabilities	$	28,497	$	77,144	$	58,279	$	87,234

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012	Jul. 30, 2012
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
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		72,127,647
Alabama Gas Corporation
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
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

XML

Asset Retirement Obligations

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

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

During the six months ended June 30, 2012, 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 of ARO as of December 31, 2011	$	107,340
Liabilities incurred	2,122
Liabilities settled	(343		)
Accretion expense	3,674
Balance of ARO as of June 30, 2012	$	112,793

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. Alagasco recorded a conditional asset retirement obligation, on a discounted basis of $21.3 million and $20.8 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of June 30, 2012, and December 31, 2011, respectively. The costs associated with asset retirement obligations are currently either being recovered in rates or are probable of recovery in future rates.

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. Regulatory assets for accumulated asset removal costs of $0.1 million and $1 million as of June 30, 2012 and December 31, 2011, respectively, are included as regulatory assets in noncurrent assets on the balance sheets. As of June 30, 2012 and December 31, 2011, the Company recognized $18.4 million and $20.3 million, respectively, of refundable negative salvage as regulatory liabilities in current liabilities on the balance sheet in response to the June 28, 2010, APSC order. As of June 30, 2012 and December 31, 2011, the Company recognized $55.1 million and $65.6 million, respectively, of refundable negative salvage as regulatory liabilities in deferred credit and other liabilities on the balance sheet in response to the June 28, 2010, APSC order.

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Consolidated Condensed Statements of Comprehensive Income of Energen Corporation (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Current period change in fair value of commodity derivative instruments, tax	$ 68,741	$ 30,307	$ 61,243	$ (29,067)
Amortization of net obligation at transition, tax	25	24	50	48
Amortization of prior service cost, tax	30	26	59	52
Amortization of net loss, tax	413	318	826	635
Current period change in fair value of interest rate swap, tax	(566)		(830)
Commodity Contract [Member]
Reclassification adjustment for derivative instruments, tax	(9,682)	2,474	(9,379)	217
Interest Rate Swap [Member]
Reclassification adjustment for derivative instruments, tax	$ 144		$ 280

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Segment Information

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

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

	Three months ended						Six months ended
	June 30,						June 30,
(in thousands)	2012			2011			2012			2011
Operating revenues
Oil and gas operations	$	399,468		$	244,090		$	623,425		$	460,882
Natural gas distribution	70,887			86,309			265,374			355,881
Total	$	470,355		$	330,399		$	888,799		$	816,763
Operating income (loss)
Oil and gas operations	$	216,406		$	105,418		$	242,411		$	190,477
Natural gas distribution	4,448			1,163			83,008			76,222
Eliminations and corporate expenses	(256		)	(246		)	(651		)	(483		)
Total	$	220,598		$	106,335		$	324,768		$	266,216
Other income (expense)
Oil and gas operations	$	(12,004	)	$	(5,822	)	$	(22,562	)	$	(11,269	)
Natural gas distribution	(3,784		)	(3,040		)	(6,788		)	(5,953		)
Eliminations and other	30			65			86			88
Total	$	(15,758	)	$	(8,797	)	$	(29,264	)	$	(17,134	)
Income before income taxes	$	204,840		$	97,538		$	295,504		$	249,082

(in thousands)	June 30, 2012		December 31, 2011
Identifiable assets
Oil and gas operations	$	4,596,172	$	4,046,242
Natural gas distribution	1,108,228		1,163,959
Eliminations and other	75,140		27,215
Total	$	5,779,540	$	5,237,416

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Reconciliation of Earnings Per Share (EPS)

6 Months Ended

Jun. 30, 2012

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)	June 30, 2012					June 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	131,287	72,117	$	1.82	$	63,325	72,065	$	0.88
Effect of dilutive securities
Stock options			205					347
Non-vested restricted stock			8					8
Diluted EPS	$	131,287	72,330	$	1.82	$	63,325	72,420	$	0.87

	Six months ended					Six months ended
(in thousands, except per share amounts)	June 30, 2012					June 30, 2011
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	188,693	72,110	$	2.62	$	157,593	72,033	$	2.19
Effect of dilutive securities
Stock options			218					324
Non-vested restricted stock			8					7
Diluted EPS	$	188,693	72,336	$	2.61	$	157,593	72,364	$	2.18

For the three months and six months ended June 30, 2012, the Company had 856,843 and 849,583, respectively, options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months and six months ended June 30, 2011, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

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Derivative Commodity Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Derivative [Line Items]

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

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

(in thousands)	June 30, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	102,499			$	—		$	102,499
Long-term asset derivative instruments	85,205				—			85,205
Total derivative assets	187,704				—			187,704
Accounts receivable	(13,592		)	*	—			(13,592		)
Long-term asset derivative instruments	(11,831		)	*	—			(11,831		)
Accounts payable	(3,940		)		—			(3,940		)
Long-term liability derivative instruments	(45		)		—			(45		)
Total derivative liabilities	(29,408		)		—			(29,408		)
Total derivatives designated	158,296				—			158,296
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,256				—			14,256
Long-term asset derivative instruments	29,899				—			29,899
Total derivative assets	44,155				—			44,155
Accounts payable	1,834			*	(30,574		)	(28,740		)
Total derivative liabilities	1,834				(30,574		)	(28,740		)
Total derivatives not designated	45,989				(30,574		)	15,415
Total derivatives	$	204,285			$	(30,574	)	$	173,711

(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

* 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 Income Statement	Three months ended June 30, 2012		Three months ended June 30, 2011
Gain recognized in OCI on derivative (effective portion), net of tax of $68.7 million and $30.3 million	—	$	112,158	$	49,449
Gain (loss) reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	21,143	$	(5,770	)
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	4,336	$	(740	)

(in thousands)	Location on Income Statement	Six months ended June 30, 2012		Six months ended June 30, 2011
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of $61.2 million and ($29.1) million	—	$	99,923	$	(47,425	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	23,013	$	1,821
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	1,669	$	(2,391	)

Schedule of Derivatives Not Designated as Hedging Instruments on Income Statements

The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:

(in thousands)	Location on Income Statement	Three months ended June 30, 2012		Three months ended June 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	123,448	$	(1	)

(in thousands)	Location on Income Statement	Six months ended June 30, 2012		Six months ended June 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	79,443	$	(1	)

Schedule of Hedging Transactions

Energen Resources entered into the following transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2012	6.7	Bcf	$4.62 Mcf	NYMEX Swaps
	18.1	Bcf	$4.15 Mcf	Basin Specific Swaps - San Juan
	3.0	Bcf	$2.89 Mcf	Basin Specific Swaps - Permian
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	9.1	Bcf	$4.65 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.79 Mcf	Basin Specific Swaps - Permian
Oil
2012	3,613	MBbl	$88.53 Bbl	NYMEX Swaps
2013	8,098	MBbl	$90.65 Bbl	NYMEX Swaps
2014	7,892	MBbl	$92.70 Bbl	NYMEX Swaps
Oil Basis Differential
2012	1,523	MBbl	$(2.95) Bbl	WTS/WTI Basis Swaps*
2013	2,768	MBbl	$(3.40) Bbl	WTS/WTI Basis Swaps*
Natural Gas Liquids
2012	30.0	MMGal	$0.98 Gal	Liquids Swaps
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

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

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

	June 30, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	42,528		$	60,635		$	103,163
Noncurrent assets	59,468			43,805			103,273
Current liabilities	(32,185		)	(495		)	(32,680		)
Noncurrent liabilities	444			(489		)	(45		)
Net derivative asset	$	70,255		$	103,456		$	173,711

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

* 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)	June 30, 2012			June 30, 2011
Balance at beginning of period	$	104,923		$	16,927
Realized gains	4,858			1,204
Unrealized gains relating to instruments held at the reporting date	12,970			7,720
Settlements during period	(19,295		)	(12,405		)
Balance at end of period	$	103,456		$	13,446

	Six months ended			Six months ended
(in thousands)	June 30, 2012			June 30, 2011
Balance at beginning of period	$	65,801		$	42,755
Realized gains	4,858			1,204
Unrealized gains (losses) relating to instruments held at the reporting date	67,209			(3,554		)
Settlements during period	(34,412		)	(26,959		)
Balance at end of period	$	103,456		$	13,446

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 June 30, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2012	$	24,620		Discounted Cash Flow	Forward Basis	($0.13 - $0.16) Mcf
2013	$	36,216		Discounted Cash Flow	Forward Basis	($0.13 - $0.17) Mcf
2014	$	22,498		Discounted Cash Flow	Forward Basis	($0.13 - $0.16) Mcf
Natural Gas Basis - Permian
2012	$	(24	)	Discounted Cash Flow	Forward Basis	($0.11) Mcf
2013	$	(2	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(105	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
Oil Basis - WTS/WTI
2012	$	2,116		Discounted Cash Flow	Forward Basis	($4.34 - $4.57) Bbl
2013	$	(1,997	)	Discounted Cash Flow	Forward Basis	($2.65) Bbl
Natural Gas Liquids
2012	$	8,617		Discounted Cash Flow	Forward Price	$0.69 - $0.81 Gal
2013	$	11,517		Discounted Cash Flow	Forward Price	$0.72 - $0.78 Gal

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

Alabama Gas Corporation

Derivative [Line Items]

Schedule of Hedging Transactions

Alagasco entered into the following natural gas transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Description
2012	7.6	Bcf	NYMEX Swaps
2013	1.5	Bcf	NYMEX Swaps

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Acquisition and Dispositions of Oil and Gas Properties

6 Months Ended

Jun. 30, 2012

Acquisition and Dispositions of Oil and Gas Properties [Abstract]

Acquisition and Dispositions of Oil and Gas Properties

ACQUISITION AND DISPOSITION OF OIL AND GAS PROPERTIES

During the first quarter of 2012, Energen Resources recognized a noncash impairment writedown on certain properties in East Texas of $21.5 million pre-tax to adjust the carrying amount of these properties to their fair value based on expected future discounted cash flows. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated production declines, and a discount rate of 10 percent commensurate with the risk of the underlying cash flow estimates. The impairment was caused by the impact of lower future natural gas prices. During the first quarter of 2012, future natural gas price curves shifted significantly lower, especially in the next 5 years. This nonrecurring impairment writedown is classified as Level 3 fair value.

On February 21, 2012, Energen Resources entered into a definitive agreement with BHP Billiton (BHP) to buy a 50 percent undivided interest in three existing wells in Reeves County, Texas, from Energen Resources for approximately $18 million. Following the purchase of the wells, BHP completed two of the wells and earned a 50 percent undivided interest in 4,829 net acres. The agreement also included the option for BHP to purchase from Energen Resources a 50 percent undivided interest in 51,720 net acres in the Permian Basin. On May 1, 2012, BHP elected not to exercise the option.

On February 14, 2012, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $68 million. This purchase had an effective date of December 1, 2011. Energen acquired total proved reserves of approximately 8.1 million barrels of oil equivalent (MMBOE). Of the proved reserves acquired, an estimated 81 percent are undeveloped. Approximately 64 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 14 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of February 14, 2012 (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	67,615
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	65,581
Unproved leasehold properties	911
Accounts receivable	1,358
Accounts payable	(25		)
Asset retirement obligation	(210		)
Total identifiable net assets	$	67,615

Included in the Company’s consolidated results of operations for the six months ended June 30, 2012, were $5.3 million of operating revenues and $2.6 million in operating income resulting from the operation of the properties acquired above.

On December 27, 2011, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $56 million (subject to closing adjustments). This purchase had an effective date of July 1, 2011. Energen acquired total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 27, 2011. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

(in thousands)
Consideration given
Cash (net)	$	55,994
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	32,045
Unproved leasehold properties	23,686
Accounts receivable	680
Accounts payable	(244		)
Asset retirement obligation	(173		)
Total identifiable net assets	$	55,994

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

On November 16, 2011, Energen completed the purchase of certain liquids-rich properties in the Permian Basin for a cash purchase price of $162 million . This purchase had an effective date of August 1, 2011. Energen acquired total proved reserves of approximately 13.6 million MMBOE. Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 percent. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition. Pro forma financial information for this acquisition is not presented because it would not be materially different from the information presented in the consolidated statements of income.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of November 16, 2011, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	161,967
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,544
Unproved leasehold properties	7,883
Accounts receivable	3,070
Accounts payable	(388		)
Asset retirement obligation	(142		)
Total identifiable net assets	$	161,967

The impact to operating revenues and operating income from this acquisition was not material for the year ended December 31, 2011.

In July 2011, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $20 million. In April 2011, Energen completed the purchase of unproved leasehold properties for a cash purchase price of approximately $37 million covering an estimated 11,000 net acres in the Permian Basin.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES    

Commitments and Agreements: Certain of Alagasco's long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $79 million through September 2024. During the six months ending June 30, 2012 and 2011, Alagasco recognized approximately $25.9 million and $25.8 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 180 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 June 30, 2012, the fixed price purchases under these guarantees had a maximum term outstanding through March 2013 and an aggregate purchase price of $2.1 million with a market value of $1.8 million.

Energen Resources entered into three agreements which commenced at various dates from November 15, 2011 to January 15, 2012 and expire at various dates through January 2015 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of these drilling rigs, Energen Resources' total resulting exposure could be as much as $26 million depending on the contractor's ability to remarket the drilling rig.

Income Taxes: The Company and Alagasco have on-going tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur as a result of the completion of various audits and the expiration of statute of limitations. Although the timing and outcome of these tax examinations is highly uncertain, the Company does not expect the change in the unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

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

Various pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability. This provision was increased by $2.0 million during the six months ended June 30, 2012.

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

Alagasco is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns and is the subject of a recent inquiry discussed below. Also discussed below is the recent completion of a removal action at the Huntsville, Alabama manufactured gas plant site. An investigation of the sites does not indicate the present need for other remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the financial position of Alagasco.

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

In June 2009, Alagasco received a General Notice Letter from the EPA identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949. While Alagasco no longer owns the Huntsville site, the Company and the current site owner entered into a Consent Order, and developed and completed during 2011 an action plan for the site. Alagasco has incurred costs associated with the site of approximately $4.9 million. As of June 30, 2012, the expected remaining costs are not expected to be material to the Company. Alagasco has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account of which a debit balance of $4.8 million was cleared as of September 30, 2011 and allocated, subject to APSC review guidelines, against the refundable negative salvage costs being refunded to customers.

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 $22 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 June 30, 2012.

Capital Lease Obligations: During the first quarter of 2012, the Company entered into certain capital leases related to certain equipment. The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of June 30, 2012:

(in thousands)
2012	$	872
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,503
Less amount representing interest	115
Total present value of minimum lease payments	$	4,388

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Stock Compensation

6 Months Ended

Jun. 30, 2012

Share-based Compensation [Abstract]

Stock Compensation

STOCK COMPENSATION

Stock Incentive Plan

The Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Stock Incentive Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 371,040 non-qualified option shares during the first quarter of 2012 with a grant-date fair value of $18.79.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. During the six months ended June 30, 2012, Energen Resources awarded 96,480, 3,768 and 40,822 Petrotech units with a three-year, two-year and 18 month vesting period, respectively. These awards have a fair value of $43.76, $44.30 and $44.58 per unit, respectively, as of June 30, 2012. In July 2012, Energen Resources awarded 5,869 Petrotech units with a three-year vesting period.

1997 Deferred Compensation Plan

During the three months and six months ended June 30, 2012, the Company had noncash purchases of approximately $35,000 and $118,000, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

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Employee Benefit Plans

6 Months Ended

Jun. 30, 2012

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

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	2,632		$	2,293		$	5,264		$	4,586
Interest cost	2,700			2,740			5,400			5,480
Expected long-term return on assets	(3,563		)	(3,868		)	(7,126		)	(7,736		)
Actuarial loss	2,099			1,609			4,198			3,218
Prior service cost amortization	129			124			259			248
Net periodic expense	$	3,997		$	2,898		$	7,995		$	5,796

The Companyanticipates required contributions of approximately $12.8 million during 2012 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. 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. No additional discretionary contributions are currently expected to be made to the pension plans by the Company during 2012. For the three months and six months ending June 30, 2012, the Company made benefit payments aggregating $36,000 and $2.3 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $0.1 million through the remainder of 2012.

During the second quarter of 2012, Congress passed the Moving Ahead for Progress in the 21st Century Act, which included pension funding stabilization provisions. The measure, which is designed to stabilize the discount rate used to determine funding requirements from the effects of interest rate volatility, is not expected to reduce the Company's pension plan cash contributions materially during 2012.

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	463		$	442		$	927		$	885
Interest cost	1,062			1,111			2,124			2,222
Expected long-term return on assets	(1,109		)	(1,104		)	(2,219		)	(2,209		)
Actuarial loss	9			—			18			—
Transition amortization	479			479			959			958
Net periodic expense	$	904		$	928		$	1,809		$	1,856

For the three months and six months ended June 30, 2012, the Company made contributions aggregating $0.9 million and $1.8 million, respectively, to the postretirement benefit plans. The Company expects to make additional discretionary contributions of approximately $1.8 million to the postretirement benefit plans through the remainder of 2012.

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Financial Instruments

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Financial Instruments

FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen's long-term debt, including the current portion, approximates $1,234.6 million and has a carrying value of $1,155.1 million at June 30, 2012. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $281.5 million and has a carrying value of $250.1 million at June 30, 2012. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

In December 2011, the Company entered into interest rate swap agreements for $200 million of the Senior Term Loans. The swap agreements exchange a variable interest rate for a fixed interest rate of 2.4175 percent on $200 million of the principal amount outstanding. The fair value of the Company's interest rate swap was a $3.0 million liability at June 30, 2012 and is classified as Level 1 fair value.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At June 30, 2012, and December 31, 2011, Alagasco’s finance receivable totaled $10.3 million and $10.5 million, respectively. These finance receivables currently have an average balance of approximately $3,000 and with terms of up to 60 months. Financing is available only to qualified customers who meet credit worthiness thresholds for customer payment history and external agency credit reports. Alagasco relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third-party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third-party collection agency. Alagasco had finance receivables past due 90 days or more of $431,000 as of June 30, 2012.

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

(in thousands)
Allowance for credit losses as of December 31, 2011	$	421
Provision	(2		)
Allowance for credit losses as of June 30, 2012	$	419

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Derivative Commodity Instruments - Derivative Instruments by Income Statement Location (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Gain recognized in OCI on derivative (effective portion), net of tax	$ 112,158,000	$ 49,449,000	$ 99,923,000	$ (47,425,000)
Loss recognized in OCI on derivative (effective portion), tax effect	68,700,000	30,300,000	61,200,000	(29,100,000)
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	50,600,000
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net			100,000
Fair Value Hedging [Member] | Natural Gas [Member] | 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	3,000,000,000		3,000,000,000
Fair Value Hedging [Member] | Natural Gas [Member] | 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	5,600,000,000		5,600,000,000
Fair Value Hedging [Member] | Natural Gas [Member] | 2014
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	4,600,000,000		4,600,000,000
Fair Value Hedging [Member] | Crude Oil [Member] | 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	2,300,000		2,300,000
Fair Value Hedging [Member] | Crude Oil [Member] | 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	6,100,000		6,100,000
Fair Value Hedging [Member] | Crude Oil [Member] | 2014
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	3,900,000		3,900,000
Fair Value Hedging [Member] | Natural Gas Liquids [Member] | 2012
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	7,600,000		7,600,000
Fair Value Hedging [Member] | Natural Gas Liquids [Member] | 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Nonmonetary Notional Amount	1,600,000		1,600,000
Operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from accumulated OCI into income (effective portion)	21,143,000	(5,770,000)	23,013,000	1,821,000
Gain (Loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	4,336,000	(740,000)	1,669,000	(2,391,000)
Gain (loss) recongnized in income on derivative	$ 123,448,000	$ (1,000)	$ 79,443,000	$ (1,000)

XML

Acquisition and Dispositions of Oil and Gas Properties (Details) (USD $)	3 Months Ended		6 Months Ended		0 Months Ended		3 Months Ended	0 Months Ended													1 Months Ended		0 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Feb. 21, 2012 Feb 21, 2012, Reeves County [Member] A well	Feb. 14, 2012 Feb 14, 2012, Permian Basin [Member] mmboe	Jun. 30, 2012 Feb 14, 2012, Permian Basin [Member]	Feb. 14, 2012 Feb 14, 2012, Permian Basin [Member] Oil Reserves	Feb. 14, 2012 Feb 14, 2012, Permian Basin [Member] Natural Gas Liquids Reserves	Feb. 14, 2012 Feb 14, 2012, Permian Basin [Member] Natural Gas Reserves	Dec. 27, 2011 Dec 27, 2011, Permian Basin [Member] mmboe	Dec. 27, 2011 Dec 27, 2011, Permian Basin [Member] Oil Reserves	Dec. 27, 2011 Dec 27, 2011, Permian Basin [Member] Natural Gas Liquids Reserves	Dec. 27, 2011 Dec 27, 2011, Permian Basin [Member] Natural Gas Reserves	Nov. 16, 2011 Nov 16, 2011, Permian Basin [Member] mmboe	Nov. 16, 2011 Nov 16, 2011, Permian Basin [Member] Oil Reserves	Nov. 16, 2011 Nov 16, 2011, Permian Basin [Member] Natural Gas Liquids Reserves	Nov. 16, 2011 Nov 16, 2011, Permian Basin [Member] Natural Gas Reserves	Jul. 31, 2011 July 2011, Permian Basin	Apr. 30, 2011 April 2011, Permian Basin A	Mar. 31, 2012 Contingent Sales Agreement [Member] Feb 21, 2012, Reeves County [Member]	Feb. 14, 2012 Contingent Sales Agreement [Member] Feb 21, 2012, Reeves County [Member] A	May 01, 2012 Contingent Sales Agreement [Member] New Contract, Second Clause [Member] Feb 21, 2012, Reeves County [Member] A
Significant Acquisitions and Disposals [Line Items]
Asset Impairment Charges	$ 0	$ 0	$ 21,545,000	$ 0
Standardized Measure of Discounted Percentage of Future Net Cash Flow of Proved Oil and Gas Reserves, Other	10.00%
Significant Acquisitions and Disposals, Percentage of Undivided Interest, Sale					50.00%																50.00%		50.00%
Wells in Process of Drilling					3
Proceeds from Sale of Oil and Gas Property and Equipment					18,000,000
Gas and Oil Acreage, Undeveloped, Net					4,829															11,000		51,720	51,720
Consideration - Purchase Price						67,615,000					55,994,000				161,967,000				20,000,000	37,000,000
Proved Developed and Undeveloped Reserves, Net						8.1					3.4				13.6
Percentage of Undeveloped Portion of Proved Reserves						81.00%					77.00%				76.00%
Acquired Proved Reserves by Type of Reserve, Percentage								64.00%	22.00%	14.00%		61.00%	24.00%	15.00%		59.00%	25.00%	16.00%
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties						65,581,000					32,045,000				151,544,000
Unproved leasehold properties						911,000					23,686,000				7,883,000
Accounts receivable						1,358,000					680,000				3,070,000
Accounts payable						(25,000)					(244,000)				(388,000)
Asset retirement obligation						(210,000)					(173,000)				(142,000)
Total identifiable net assets						67,615,000					55,994,000				161,967,000
Operating revenues	470,355,000	330,399,000	888,799,000	816,763,000			5,300,000
Operating income	$ 220,598,000	$ 106,335,000	$ 324,768,000	$ 266,216,000			$ 2,600,000

XML

Derivative Commodity Instruments Derivative Commodity Investments (Policies)

6 Months Ended

Jun. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives, Policy

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

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which does not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with all of its active counterparties at June 30, 2012. The five largest counterparty net gain positions at June 30, 2012, Macquarie Bank Limited, J Aron & Company, Citibank, N.A., Shell Energy North America (US), L.P. and BP Corporation North America Inc. constituted approximately $33.1 million, $31.2 million, $23.9 million, $22.9 million and $19.8 million, respectively, of Energen Resources’ net gain on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of June 30, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

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Employee Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2012

Pension Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	2,632		$	2,293		$	5,264		$	4,586
Interest cost	2,700			2,740			5,400			5,480
Expected long-term return on assets	(3,563		)	(3,868		)	(7,126		)	(7,736		)
Actuarial loss	2,099			1,609			4,198			3,218
Prior service cost amortization	129			124			259			248
Net periodic expense	$	3,997		$	2,898		$	7,995		$	5,796

Postretirement Benefit Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2012			2011			2012			2011
Components of net periodic benefit cost:
Service cost	$	463		$	442		$	927		$	885
Interest cost	1,062			1,111			2,124			2,222
Expected long-term return on assets	(1,109		)	(1,104		)	(2,219		)	(2,209		)
Actuarial loss	9			—			18			—
Transition amortization	479			479			959			958
Net periodic expense	$	904		$	928		$	1,809		$	1,856

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Regulatory Assets and Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 60,485	$ 57,143
Regulatory Assets, Noncurrent	89,785	95,633
Regulatory Liability, Current	28,497	58,279
Regulatory Liability, Noncurrent	77,144	87,234
Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	18,400	20,300
Regulatory Liability, Noncurrent	55,100	65,600
Alabama Gas Corporation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	60,485	57,143
Regulatory Assets, Noncurrent	89,785	95,633
Regulatory Liability, Current	28,497	58,279
Regulatory Liability, Noncurrent	77,144	87,234
Alabama Gas Corporation | RSE adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	4,586	2,931
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Unbilled service margin
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	5,518	22,419
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Gas Supply Adjustment [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	12,626
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	18,360	20,269
Regulatory Liability, Noncurrent	55,079	65,646
Alabama Gas Corporation | Asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	21,278	20,785
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	33	34
Regulatory Liability, Noncurrent	787	803
Alabama Gas Corporation | Pension and postretirement assets
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	170	170
Regulatory Assets, Noncurrent	74,742	77,587
Alabama Gas Corporation | Accretion and depreciation for asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	14,584	13,981
Alabama Gas Corporation | Risk management activities
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	30,573	56,804
Regulatory Assets, Noncurrent	0	3,070
Alabama Gas Corporation | Asset removal costs, net
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	126	994
Alabama Gas Corporation | Gas Supply Adjustment [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	29,671	0
Regulatory Assets, Noncurrent	0	0
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	71	169
Regulatory Assets, Noncurrent	$ 333	$ 1

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Segment Reporting Information, Profit (Loss)
Operating revenues	$ 470,355	$ 330,399	$ 888,799	$ 816,763
Operating income (loss)	220,598	106,335	324,768	266,216
Other income (expense)	(15,758)	(8,797)	(29,264)	(17,134)
Income before income taxes	204,840	97,538	295,504	249,082
Identifiable assets	5,779,540		5,779,540		5,237,416
Oil and Gas Operations
Segment Reporting Information, Profit (Loss)
Operating revenues	399,468	244,090	623,425	460,882
Operating income (loss)	216,406	105,418	242,411	190,477
Other income (expense)	(12,004)	(5,822)	(22,562)	(11,269)
Identifiable assets	4,596,172		4,596,172		4,046,242
Natural Gas Distribution
Segment Reporting Information, Profit (Loss)
Operating revenues	70,887	86,309	265,374	355,881
Operating income (loss)	4,448	1,163	83,008	76,222
Other income (expense)	(3,784)	(3,040)	(6,788)	(5,953)
Identifiable assets	1,108,228		1,108,228		1,163,959
Eliminations and other
Segment Reporting Information, Profit (Loss)
Operating income (loss)	(256)	(246)	(651)	(483)
Other income (expense)	30	65	86	88
Identifiable assets	$ 75,140		$ 75,140		$ 27,215

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Consolidated Condensed Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 61,306	$ 9,541
Accounts receivable
Allowance for doubtful accounts	(7,744)	(12,946)
Accounts receivable, net of allowance for doubtful accounts of $6,848 at June 30, 2012, and $12,946 at December 31, 2011	247,095	231,925
Inventories
Storage gas inventory	35,650	44,047
Materials and supplies	36,089	26,420
Liquified natural gas in storage	3,689	3,545
Regulatory asset	60,485	57,143
Income tax receivable	2,942	7,343
Deferred income taxes	12,546	48,818
Prepayments and other	11,647	15,386
Total current assets	471,449	444,168
Property, Plant and Equipment
Oil and gas properties, successful efforts method	5,796,145	5,166,368
Less accumulated depreciation, depletion and amortization	1,576,618	1,382,526
Oil and gas properties, net	4,219,527	3,783,842
Utility plant	1,383,563	1,358,266
Less accumulated depreciation	557,137	544,838
Utility plant, net	826,426	813,428
Other property, net	23,914	23,506
Total property, plant and equipment, net	5,069,867	4,620,776
Other Assets
Regulatory asset	89,785	95,633
Long-term derivative instruments	103,273	31,056
Deferred charges and other	45,166	45,783
Total other assets	238,224	172,472
TOTAL ASSETS	5,779,540	5,237,416
Current Liabilities
Long-term debt due within one year	1,000	1,000
Notes payable to banks	310,000	15,000
Accounts payable	252,586	302,048
Affiliated Companies		0
Accrued taxes	74,158	32,359
Customers' deposits	24,117	23,950
Amounts due customers	15,542	21,065
Accrued wages and benefits	22,799	35,258
Regulatory liability	28,497	58,279
Royalty payable	30,570	22,592
Other	30,292	32,328
Total current liabilities	789,561	543,879
Long-term debt	1,153,599	1,153,700
Deferred Credits and Other Liabilities
Asset retirement obligation	112,793	107,340
Pension and other postretirement liabilities	64,352	62,532
Regulatory liability	77,144	87,234
Long-term derivative instruments	1,624	34,663
Deferred income taxes	877,749	806,127
Other	10,174	9,778
Total deferred credits and other liabilities	1,143,836	1,107,674
Commitments and Contingencies
Shareholders' Equity
Preferred stock, cumulative $0.01 par value	0	0
Common shareholders' equity
Common stock, $0.01 par value	750	750
Premium on capital stock	489,584	482,918
Capital surplus	2,802	2,802
Retained earnings	2,269,385	2,100,885
Accumulated other comprehensive loss, net of tax
Unrealized gain (loss) on hedges, net	93,893	9,273
Pension and postretirement plans	(36,848)	(38,584)
Interest rate swap	(1,963)	(941)
Deferred compensation plan	3,632	3,511
Treasury stock, at cost; 3,037,234 shares at June 30, 2012, and 3,036,549 shares at December 31, 2011	(128,691)	(128,451)
Total shareholders' equity	2,692,544	2,432,163
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	5,779,540	5,237,416
Alabama Gas Corporation
Current Assets
Cash and cash equivalents	15,927	7,817
Accounts receivable
Gas	37,855	96,812
Other	5,058	6,858
Affiliated companies	0	2,841
Allowance for doubtful accounts	(6,000)	(12,100)
Inventories
Storage gas inventory	35,650	44,047
Materials and supplies	4,962	4,183
Liquified natural gas in storage	3,689	3,545
Regulatory asset	60,485	57,143
Income tax receivable	1,904	9,762
Deferred income taxes	20,876	21,986
Prepayments and other	1,736	4,422
Total current assets	182,142	247,316
Property, Plant and Equipment
Utility plant	1,383,563	1,358,266
Less accumulated depreciation	557,137	544,838
Utility plant, net	826,426	813,428
Other property, net	42	43
Other Assets
Regulatory asset	89,785	95,633
Deferred charges and other	9,833	10,380
Total other assets	99,618	106,013
TOTAL ASSETS	1,108,228	1,166,800
Current Liabilities
Notes payable to banks	0	15,000
Accounts payable	59,678	110,552
Affiliated Companies	14,304
Accrued taxes	36,065	26,861
Customers' deposits	24,117	23,950
Amounts due customers	15,542	21,065
Accrued wages and benefits	8,920	12,971
Regulatory liability	28,497	58,279
Other	10,256	9,250
Total current liabilities	197,379	277,928
Long-term debt	250,123	250,246
Deferred Credits and Other Liabilities
Pension and other postretirement liabilities	22,522	21,383
Regulatory liability	77,144	87,234
Long-term derivative instruments	0	3,070
Deferred income taxes	186,548	181,492
Other	634	709
Total deferred credits and other liabilities	286,848	293,888
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	339,374	310,234
Accumulated other comprehensive loss, net of tax
Total shareholders' equity	373,878	344,738
Total capitalization	624,001	594,984
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 1,108,228	$ 1,166,800

XML

Derivative Commodity Instruments

6 Months Ended

Jun. 30, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Commodity Instruments

DERIVATIVE COMMODITY INSTRUMENTS

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

Energen Resources periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply pursuant to standing authorizations by the Board of Directors, which does not authorize speculative positions. Such instruments may include over-the-counter (OTC) swaps and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with all of its active counterparties at June 30, 2012. The five largest counterparty net gain positions at June 30, 2012, Macquarie Bank Limited, J Aron & Company, Citibank, N.A., Shell Energy North America (US), L.P. and BP Corporation North America Inc. constituted approximately $33.1 million, $31.2 million, $23.9 million, $22.9 million and $19.8 million, respectively, of Energen Resources’ net gain on fair value of derivatives.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of June 30, 2012, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most of the agreements include various contractual set-off rights, which may be exercised by the non-defaulting party in the event of an early termination due to a default.

The Company periodically enters into derivative transactions that do not qualify for cash flow hedge accounting but are considered by management to represent valid economic hedges and are accounted for as mark-to-market transactions. These economic hedges may include, but are not limited to, hedges on estimated future production not yet flowing, basis hedges without a corresponding New York Mercantile Exchange (NYMEX) hedge and hedges on non-operated or other properties for which all of the necessary information to qualify for cash flow hedge accounting is either not readily available or subject to change. Derivatives that do not qualify for hedge treatment or are not designated as cash flow hedges are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

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

(in thousands)	June 30, 2012
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	102,499			$	—		$	102,499
Long-term asset derivative instruments	85,205				—			85,205
Total derivative assets	187,704				—			187,704
Accounts receivable	(13,592		)	*	—			(13,592		)
Long-term asset derivative instruments	(11,831		)	*	—			(11,831		)
Accounts payable	(3,940		)		—			(3,940		)
Long-term liability derivative instruments	(45		)		—			(45		)
Total derivative liabilities	(29,408		)		—			(29,408		)
Total derivatives designated	158,296				—			158,296
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	14,256				—			14,256
Long-term asset derivative instruments	29,899				—			29,899
Total derivative assets	44,155				—			44,155
Accounts payable	1,834			*	(30,574		)	(28,740		)
Total derivative liabilities	1,834				(30,574		)	(28,740		)
Total derivatives not designated	45,989				(30,574		)	15,415
Total derivatives	$	204,285			$	(30,574	)	$	173,711

(in thousands)	December 31, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	73,636			$	—		$	73,636
Long-term asset derivative instruments	75,982				—			75,982
Total derivative assets	149,618				—			149,618
Accounts receivable	(48,174		)	*	—			(48,174		)
Long-term asset derivative instruments	(36,341		)	*	—			(36,341		)
Accounts payable	(37,070		)		—			(37,070		)
Long-term liability derivative instruments	(20,386		)		—			(20,386		)
Total derivative liabilities	(141,971		)		—			(141,971		)
Total derivatives designated	7,647				—			7,647
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	(3,670		)	*	—			(3,670		)
Long-term asset derivative instruments	(8,585		)	*	—			(8,585		)
Total derivative assets	(12,255		)		—			(12,255		)
Accounts payable	(13,416		)		(56,804		)	(70,220		)
Long-term liability derivative instruments	(10,922		)		(3,070		)	(13,992		)
Total derivative liabilities	(24,338		)		(59,874		)	(84,212		)
Total derivatives not designated	(36,593		)		(59,874		)	(96,467		)
Total derivatives	$	(28,946	)		$	(59,874	)	$	(88,820	)

* 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 $57.5 million and a net $5.7 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of June 30, 2012, and December 31, 2011, respectively.

Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff and are recognized as a regulatory asset or regulatory liability.

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

(in thousands)	Location on Income Statement	Three months ended June 30, 2012		Three months ended June 30, 2011
Gain recognized in OCI on derivative (effective portion), net of tax of $68.7 million and $30.3 million	—	$	112,158	$	49,449
Gain (loss) reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	21,143	$	(5,770	)
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	4,336	$	(740	)

(in thousands)	Location on Income Statement	Six months ended June 30, 2012		Six months ended June 30, 2011
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of $61.2 million and ($29.1) million	—	$	99,923	$	(47,425	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	23,013	$	1,821
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	1,669	$	(2,391	)

The following table details the effect of derivative commodity instruments not designated as hedging instruments on the income statements:

(in thousands)	Location on Income Statement	Three months ended June 30, 2012		Three months ended June 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	123,448	$	(1	)

(in thousands)	Location on Income Statement	Six months ended June 30, 2012		Six months ended June 30, 2011
Gain (loss) recognized in income on derivative	Operating revenues	$	79,443	$	(1	)

As of June 30, 2012, $50.6 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of June 30, 2012, the Company had 3 billion, 5.6 billion and 4.6 billion cubic feet (Bcf) of natural gas hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 2.3 million, 6.1 million and 3.9 million barrels (MMBbl) of oil and oil basis hedges which expire during 2012, 2013 and 2014, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 7.6 million and 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2012 and 2013, respectively, that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. During 2011, the Company had a discontinuance of hedge accounting when Energen Resources determined it was probable certain forecasted volumes would not occur, which resulted in $0.1 million after-tax gain being recognized into operating revenues during the six months ended June 30, 2012.

Energen Resources entered into the following transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Average Contract Price	Description
Natural Gas
2012	6.7	Bcf	$4.62 Mcf	NYMEX Swaps
	18.1	Bcf	$4.15 Mcf	Basin Specific Swaps - San Juan
	3.0	Bcf	$2.89 Mcf	Basin Specific Swaps - Permian
2013	12.7	Bcf	$4.82 Mcf	NYMEX Swaps
	32.8	Bcf	$4.56 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.45 Mcf	Basin Specific Swaps - Permian
2014	9.1	Bcf	$4.65 Mcf	NYMEX Swaps
	25.7	Bcf	$4.72 Mcf	Basin Specific Swaps - San Juan
	4.6	Bcf	$3.79 Mcf	Basin Specific Swaps - Permian
Oil
2012	3,613	MBbl	$88.53 Bbl	NYMEX Swaps
2013	8,098	MBbl	$90.65 Bbl	NYMEX Swaps
2014	7,892	MBbl	$92.70 Bbl	NYMEX Swaps
Oil Basis Differential
2012	1,523	MBbl	$(2.95) Bbl	WTS/WTI Basis Swaps*
2013	2,768	MBbl	$(3.40) Bbl	WTS/WTI Basis Swaps*
Natural Gas Liquids
2012	30.0	MMGal	$0.98 Gal	Liquids Swaps
2013	44.5	MMGal	$1.02 Gal	Liquids Swaps
*WTS - West Texas Sour/Midland, WTI - West Texas Intermediate/Cushing

Alagasco entered into the following natural gas transactions for the remainder of 2012 and subsequent years:

Production Period	Total Hedged Volumes		Description
2012	7.6	Bcf	NYMEX Swaps
2013	1.5	Bcf	NYMEX Swaps

As of June 30, 2012, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014, and March 31, 2013, respectively. Alagasco has not entered into any new cash flow derivative transactions on its gas supply since the summer of 2010. 

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). All assets and liabilities are required to be classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input may require judgment considering factors specific to the asset or liability, and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. The fair value hierarchy that prioritizes the inputs used to measure fair value is as follows:

Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2 - Pricing inputs other than quoted prices in active markets included within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;

Level 3 - Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumption that market value participants would use in pricing the asset or liability. Unobservable inputs are developed based on the best available information and subject to cost-benefit constraints.

Derivative commodity instruments are over-the-counter (OTC) derivatives valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of swaps priced in reference to NYMEX natural gas and oil futures. OTC derivatives valued using unobservable market prices have been classified within Level 3 of the fair value hierarchy. These Level 3 fair values include basin specific, basis and natural gas liquids swaps. The Company considers frequency of pricing and variability in pricing between sources in determining whether a market is considered active. While the Company does not have access to the specific assumptions used in its counterparties' valuation models, the Company maintains communications with its counterparties and discusses pricing practices. Further, the Company corroborates the fair value of its transactions by comparison of market-based price sources.

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

	June 30, 2012
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	42,528		$	60,635		$	103,163
Noncurrent assets	59,468			43,805			103,273
Current liabilities	(32,185		)	(495		)	(32,680		)
Noncurrent liabilities	444			(489		)	(45		)
Net derivative asset	$	70,255		$	103,456		$	173,711

	December 31, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(14,843	)	$	36,635		$	21,792
Noncurrent assets	(8,382		)	39,438			31,056
Current liabilities	(98,468		)	(8,822		)	(107,290		)
Noncurrent liabilities	(32,928		)	(1,450		)	(34,378		)
Net derivative asset (liability)	$	(154,621	)	$	65,801		$	(88,820	)

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

As of June 30, 2012, Alagasco had $30.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities. As of December 31, 2011, Alagasco had $56.8 million and $3.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of June 30, 2012, and December 31, 2011.

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 $34 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations would be an approximate $3.8 million associated with open Level 3 mark-to-market derivative contracts. Cash flow requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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

	Three months ended			Three months ended
(in thousands)	June 30, 2012			June 30, 2011
Balance at beginning of period	$	104,923		$	16,927
Realized gains	4,858			1,204
Unrealized gains relating to instruments held at the reporting date	12,970			7,720
Settlements during period	(19,295		)	(12,405		)
Balance at end of period	$	103,456		$	13,446

	Six months ended			Six months ended
(in thousands)	June 30, 2012			June 30, 2011
Balance at beginning of period	$	65,801		$	42,755
Realized gains	4,858			1,204
Unrealized gains (losses) relating to instruments held at the reporting date	67,209			(3,554		)
Settlements during period	(34,412		)	(26,959		)
Balance at end of period	$	103,456		$	13,446

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 June 30, 2012			Valuation Technique*	Unobservable Input*	Range
Natural Gas Basis - San Juan
2012	$	24,620		Discounted Cash Flow	Forward Basis	($0.13 - $0.16) Mcf
2013	$	36,216		Discounted Cash Flow	Forward Basis	($0.13 - $0.17) Mcf
2014	$	22,498		Discounted Cash Flow	Forward Basis	($0.13 - $0.16) Mcf
Natural Gas Basis - Permian
2012	$	(24	)	Discounted Cash Flow	Forward Basis	($0.11) Mcf
2013	$	(2	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
2014	$	(105	)	Discounted Cash Flow	Forward Basis	($0.13) Mcf
Oil Basis - WTS/WTI
2012	$	2,116		Discounted Cash Flow	Forward Basis	($4.34 - $4.57) Bbl
2013	$	(1,997	)	Discounted Cash Flow	Forward Basis	($2.65) Bbl
Natural Gas Liquids
2012	$	8,617		Discounted Cash Flow	Forward Price	$0.69 - $0.81 Gal
2013	$	11,517		Discounted Cash Flow	Forward Price	$0.72 - $0.78 Gal

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

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Commitments and Contingencies Commitments and Contingencies Disclosure (Tables)

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

The following is a schedule of future minimum lease payments under capital leases together with the present value of the net minimum lease payments as of June 30, 2012:

(in thousands)
2012	$	872
2013	1,743
2014	1,743
2015	145
Total minimum lease payments	4,503
Less amount representing interest	115
Total present value of minimum lease payments	$	4,388

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Derivative Commodity Instruments - Quantitative Disclosures About Fair Value (Details) (Income Approach Valuation Technique [Member], Level 3, USD $)	3 Months Ended
	Jun. 30, 2012
Natural Gas Basis - San Juan [Member] | 2012
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	$ 24,620,000
Natural Gas Basis - San Juan [Member] | 2012 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.13
Natural Gas Basis - San Juan [Member] | 2012 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.16
Natural Gas Basis - San Juan [Member] | 2013
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	36,216,000
Natural Gas Basis - San Juan [Member] | 2013 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.13
Natural Gas Basis - San Juan [Member] | 2013 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.17
Natural Gas Basis - San Juan [Member] | 2014
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	22,498,000
Natural Gas Basis - San Juan [Member] | 2014 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.13
Natural Gas Basis - San Juan [Member] | 2014 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Cubic Foot	0.16
Natural Gas Basis - Permian [Member] | 2012
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	(24)
Fair Value Inputs, Price Per Cubic Foot	0.11
Natural Gas Basis - Permian [Member] | 2013
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	(2)
Fair Value Inputs, Price Per Cubic Foot	0.13
Natural Gas Basis - Permian [Member] | 2014
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	(105)
Fair Value Inputs, Price Per Cubic Foot	0.13
Oil Basis - WTS/WTI [Member] | 2012
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	2,116,000
Oil Basis - WTS/WTI [Member] | 2012 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Barrel	4.34
Oil Basis - WTS/WTI [Member] | 2012 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Barrel	4.57
Oil Basis - WTS/WTI [Member] | 2013
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	(1,997,000)
Fair Value Inputs, Price Per Barrel	2.65
Natural Gas Liquids [Member] | 2012
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	8,617,000
Natural Gas Liquids [Member] | 2012 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Gallon	0.69
Natural Gas Liquids [Member] | 2012 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Gallon	0.81
Natural Gas Liquids [Member] | 2013
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value as of June 30, 2012	$ 11,517,000
Natural Gas Liquids [Member] | 2013 | Minimum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Gallon	0.72
Natural Gas Liquids [Member] | 2013 | Maximum [Member]
Fair Value Inputs, Derivatives, Quantitative Information [Line Items]
Fair Value Inputs, Price Per Gallon	0.78

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Recently Issued Accounting Standards

6 Months Ended

Jun. 30, 2012

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

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

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This update requires entities to present the components of net income and other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments in this update do not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. In December 2011, the FASB issued ASU No. 2011-12, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05, which deferred the requirements to include reclassification adjustments for items that are reclassified from other comprehensive income to net income on the face of the financial statements. The amendments in these updates are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Adoption of these updates has not had a material impact on the consolidated condensed financial statements or results of operations. The Company does not expect the portions of these updates that have been deferred to have a material impact on its consolidated condensed financial statements or results of operations.

In May 2011, the FASB issued ASU No. 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirement in U.S. GAAP and International Financial Reporting Standards (IFRSs). The amendments in this update result in common fair value measurement and disclosure requirements in U.S. GAAP and IFRSs. The amendments are effective during interim and annual periods beginning after December 15, 2011. This standard did not have a material impact on the consolidated condensed financial statements of the Company. The additional fair value disclosures are included in Note 3, Derivative Commodity Instruments.