10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

____________________________________________

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011

OR

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

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

605 Richard Arrington Jr. Boulevard North

Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

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

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

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

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

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

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of November 3, 2011.

Energen Corporation	$0.01 par value	72,093,899 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2011

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 Balance Sheets of Energen Corporation	4
	(c) Consolidated Condensed Statements of Cash Flows of Energen Corporation	6
	(d) Condensed Statements of Income of Alabama Gas Corporation	7
	(e) Condensed Balance Sheets of Alabama Gas Corporation	8
	(f) Condensed Statements of Cash Flows of Alabama Gas Corporation	10
	(g) Notes to Unaudited Condensed Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	26
	Selected Business Segment Data of Energen Corporation	36
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	39
PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 5.	Other Information	40
Item 6.	Exhibits	40
SIGNATURES		41

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands, except per share data)	2011			2010			2011			2010
Operating Revenues
Oil and gas operations	$	318,952		$	234,111		$	779,834		$	706,311
Natural gas distribution	59,616			61,693			415,497			498,132
Total operating revenues	378,568			295,804			1,195,331			1,204,443
Operating Expenses
Cost of gas	21,748			22,560			185,916			262,950
Operations and maintenance	111,749			127,934			318,763			329,581
Depreciation, depletion and amortization	72,802			60,814			199,559			185,025
Taxes, other than income taxes	20,129			15,615			69,399			64,508
Accretion expense	1,728			1,561			5,066			4,568
Total operating expenses	228,156			228,484			778,703			846,632
Operating Income	150,412			67,320			416,628			357,811
Other Income (Expense)
Interest expense	(11,976		)	(9,591		)	(30,843		)	(29,395		)
Other income	619			2,222			1,727			2,555
Other expense	(2,074		)	(61		)	(1,449		)	(541		)
Total other expense	(13,431		)	(7,430		)	(30,565		)	(27,381		)
Income Before Income Taxes	136,981			59,890			386,063			330,430
Income tax expense	49,382			21,586			140,871			119,873
Net Income	$	87,599		$	38,304		$	245,192		$	210,557
Diluted Earnings Per Average Common Share	$	1.21		$	0.53		$	3.39		$	2.92
Basic Earnings Per Average Common Share	$	1.22		$	0.53		$	3.40		$	2.93
Dividends Per Common Share	$	0.135		$	0.130		$	0.405		$	0.390
Diluted Average Common Shares Outstanding	72,375			72,070			72,409			72,061
Basic Average Common Shares Outstanding	72,068			71,854			72,045			71,838

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

3

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	September 30, 2011		December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	21,396	$	22,659
Accounts receivable, net of allowance for doubtful accounts of $13,596 at September 30, 2011, and $15,048 at December 31, 2010	214,553		286,849
Inventories
Storage gas inventory	42,856		36,706
Materials and supplies	28,424		19,045
Liquified natural gas in storage	3,515		3,551
Regulatory asset	44,525		28,286
Income tax receivable	5,142		44,489
Deferred income taxes	—		32,732
Prepayments and other	17,190		11,966
Total current assets	377,601		486,283
Property, Plant and Equipment
Oil and gas properties, successful efforts method	4,725,629		4,080,779
Less accumulated depreciation, depletion and amortization	1,316,643		1,161,635
Oil and gas properties, net	3,408,986		2,919,144
Utility plant	1,339,872		1,292,611
Less accumulated depreciation	528,313		509,989
Utility plant, net	811,559		782,622
Other property, net	23,423		17,461
Total property, plant and equipment, net	4,243,968		3,719,227
Other Assets
Regulatory asset	109,244		105,365
Pension and other postretirement assets	—		13,907
Long-term derivative instruments	101,175		—
Deferred charges and other	43,454		38,778
Total other assets	253,873		158,050
TOTAL ASSETS	$	4,875,442	$	4,363,560

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

4

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands, except share and per share data)	September 30, 2011			December 31, 2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	1,000		$	5,000
Notes payable to banks	75,000			305,000
Accounts payable	212,722			268,214
Accrued taxes	50,451			52,845
Customers' deposits	21,701			20,459
Amounts due customers	20,482			20,161
Accrued wages and benefits	30,150			25,203
Regulatory liability	51,849			75,703
Royalty payable	23,810			19,221
Deferred income taxes	2,004			—
Other	27,129			26,805
Total current liabilities	516,298			818,611
Long-term debt	803,829			405,254
Deferred Credits and Other Liabilities
Asset retirement obligation	104,711			97,415
Pension and other postretirement liabilities	71,025			36,551
Regulatory liability	87,579			110,447
Long-term derivative instruments	13,331			112,936
Deferred income taxes	785,826			615,084
Other	4,942			13,219
Total deferred credits and other liabilities	1,067,414			985,652
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, 74,991,804 shares issued at September 30, 2011, and 74,786,376 shares issued at December 31, 2010	750			748
Premium on capital stock	481,616			468,934
Capital surplus	2,802			2,802
Retained earnings	2,096,187			1,880,183
Accumulated other comprehensive loss, net of tax
Unrealized gain (loss) on hedges, net	71,253			(43,667		)
Pension and postretirement plans	(39,803		)	(30,730		)
Deferred compensation plan	3,458			3,288
Treasury stock, at cost; 3,034,684 shares at September 30, 2011, and 3,024,847 shares at December 31, 2010	(128,362		)	(127,515		)
Total shareholders' equity	2,487,901			2,154,043
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	4,875,442		$	4,363,560

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

5

CONSOLIDATED CONDENSED STATEMENS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Nine months ended September 30, (in thousands)	2011			2010
Operating Activities
Net income	$	245,192		$	210,557
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	199,559			185,025
Accretion expense	5,066			4,568
Deferred income taxes	120,656			95,005
Bad debt expense	3,197			2,969
Exploratory expense	10,773			53,642
Change in derivative fair value	(59,581		)	278
Gain on sale of assets	(5,991		)	(529		)
Other, net	5,913			(4,849		)
Net change in:
Accounts receivable	48,585			51,577
Inventories	(15,493		)	(8,498		)
Accounts payable	(26,877		)	(15,449		)
Amounts due customers including gas supply pass-through	7,342			22,076
Income tax receivable	39,347			(48,284		)
Pension and other postretirement benefit contributions	(5,025		)	(40,988		)
Other current assets and liabilities	21,286			10,839
Net cash provided by operating activities	593,949			517,939
Investing Activities
Additions to property, plant and equipment	(634,427		)	(309,849		)
Acquisitions, net of cash acquired	(106,578		)	(208,667		)
Proceeds from sale of assets	7,401			607
Purchase of short-term investments	—			(154,880		)
Sale of short-term investments	—			79,938
Other, net	(946		)	(1,395		)
Net cash used in investing activities	(734,550		)	(594,246		)
Financing Activities
Payment of dividends on common stock	(29,188		)	(28,030		)
Issuance of common stock	6,221			594
Issuance of long-term debt	399,952			—
Payment of long-term debt	(5,407		)	(707		)
Net change in short-term debt	(230,000		)	42,000
Tax benefit on stock compensation	922			720
Debt issuance costs	(3,162		)	—
Net cash provided by financing activities	139,338			14,577
Net change in cash and cash equivalents	(1,263		)	(61,730		)
Cash and cash equivalents at beginning of period	22,659			75,844
Cash and Cash Equivalents at End of Period	$	21,396		$	14,114

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

6

CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Operating Revenues	$	59,616		$	61,693		$	415,497		$	498,132
Operating Expenses
Cost of gas	21,748			22,560			185,916			262,950
Operations and maintenance	33,001			33,763			106,535			98,667
Depreciation and amortization	9,980			9,451			29,606			34,380
Income taxes
Current	(9,414		)	(18,633		)	3,456			1,821
Deferred	3,664			14,619			16,626			21,889
Taxes, other than income taxes	5,568			4,934			27,899			32,757
Total operating expenses	64,547			66,694			370,038			452,464
Operating Income (Expense)	(4,931		)	(5,001		)	45,459			45,668
Other Income (Expense)
Allowance for funds used during construction	260			280			652			550
Other income	326			891			941			1,184
Other expense	(913		)	(37		)	(720		)	(373		)
Total other income (expense)	(327		)	1,134			873			1,361
Interest Charges
Interest on long-term debt	3,025			2,960			9,106			8,892
Other interest expense	810			293			1,882			1,351
Total interest charges	3,835			3,253			10,988			10,243
Net Income (Loss)	$	(9,093	)	$	(7,120	)	$	35,344		$	36,786

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

7

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	September 30, 2011			December 31, 2010
ASSETS
Property, Plant and Equipment
Utility plant	$	1,339,872		$	1,292,611
Less accumulated depreciation	528,313			509,989
Utility plant, net	811,559			782,622
Other property, net	43			43
Current Assets
Cash and cash equivalents	6,754			16,910
Accounts receivable
Gas	45,246			136,800
Other	6,766			10,229
Affiliated companies	—			698
Allowance for doubtful accounts	(12,800		)	(14,200		)
Inventories
Storage gas inventory	42,856			36,706
Materials and supplies	4,206			4,147
Liquified natural gas in storage	3,515			3,551
Regulatory asset	44,525			28,286
Income tax receivable	3,508			10,315
Deferred income taxes	25,792			27,302
Prepayments and other	6,202			4,223
Total current assets	176,570			264,967
Other Assets
Regulatory asset	109,244			105,365
Pension and other postretirement assets	—			9,201
Deferred charges and other	9,772			5,399
Total other assets	119,016			119,965
TOTAL ASSETS	$	1,107,188		$	1,167,597

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

8

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands, except share data)	September 30, 2011		December 31, 2010
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized	$	—	$	—
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at September 30, 2011 and December 31, 2010	20		20
Premium on capital stock	31,682		31,682
Capital surplus	2,802		2,802
Retained earnings	298,976		292,815
Total common shareholder's equity	333,480		327,319
Long-term debt	200,386		200,793
Total capitalization	533,866		528,112
Current Liabilities
Long-term debt due within one year	—		5,000
Notes payable to banks	50,000		70,000
Accounts payable	76,621		83,515
Affiliated Companies	370		—
Accrued taxes	29,006		48,476
Customers' deposits	21,701		20,459
Amounts due customers	20,482		20,161
Accrued wages and benefits	9,275		11,851
Regulatory liability	51,849		75,703
Other	9,150		11,822
Total current liabilities	268,454		346,987
Deferred Credits and Other Liabilities
Deferred income taxes	173,877		141,780
Pension and other postretirement liabilities	29,628		4,733
Regulatory liability	87,579		110,447
Long-term derivative instruments	13,050		32,461
Other	734		3,077
Total deferred credits and other liabilities	304,868		292,498
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,107,188	$	1,167,597

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

9

CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Nine months ended September 30, (in thousands)	2011			2010
Operating Activities
Net income	$	35,344		$	36,786
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	29,606			34,380
Deferred income taxes	16,626			21,889
Bad debt expense	3,184			2,979
Other, net	227			(16,188		)
Net change in:
Accounts receivable	41,085			40,921
Inventories	(6,173		)	(4,782		)
Accounts payable	(22,155		)	(16,381		)
Amounts due customers including gas supply pass-through	7,342			22,076
Income tax receivable	6,807			(7,990		)
Pension and other postretirement benefit contributions	(2,108		)	(25,185		)
Other current assets and liabilities	(8,474		)	8,917
Net cash provided by operating activities	101,311			97,422
Investing Activities
Additions to property, plant and equipment	(57,424		)	(74,710		)
Other, net	177			(3,807		)
Net cash used in investing activities	(57,247		)	(78,517		)
Financing Activities
Dividends	(29,183		)	(37,367		)
Payment of long-term debt	(5,407		)	(707		)
Net decreases in advances from affiliates	370			(24,962		)
Net change in short-term debt	(20,000		)	42,000
Net cash used in financing activities	(54,220		)	(21,036		)
Net change in cash and cash equivalents	(10,156		)	(2,131		)
Cash and cash equivalents at beginning of period	16,910			9,460
Cash and Cash Equivalents at End of Period	$	6,754		$	7,329

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

10

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, 2010, 2009 and 2008, included in the 2010 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 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 consisted of normal recurring items.

During the first quarter of 2010, Alagasco identified an error in calculating the estimate of the allowance for doubtful accounts as of December 31, 2009. This error resulted in a $3 million overstatement to the allowance for doubtful accounts and a corresponding overstatement of net income by approximately $0.6 million (approximately $0.01 per diluted share) after reflecting the regulatory limits on Alagasco’s allowed rate of return for rate year ending September 30, 2010, in the application of Rate Stabilization and Equalization. The Company considered the net impact of this adjustment on the prior quarterly and year-end results, and the results of Alagasco and Energen for the year ended December 31, 2010, and determined that the amount was not material to these periods. The Company corrected this error in the first quarter of 2010.

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 ended 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 remains 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and year-to-date performance, whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and nine months ended September 30, 2011, Alagasco had a net $1.2 million pre-tax and a net $6.7 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the nine months ended September 30, 2010, Alagasco had a net $10.6 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $1.3 million annual decrease and a $10.2 million annual increase in revenues became effective December 1, 2010 and 2009, 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. In the rate year ended September 30, 2010, $2.5 million of extraordinary bad debt expense was excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2011 and 2010.

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

11

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.

In 1998, the APSC approved an Enhanced Stability Reserve, with a maximum funding level of $4 million, to which Alagasco could charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) negative individual large commercial and industrial customer budget revenue variances that exceed $250,000 during the rate year, if such losses caused Alagasco's year-end return on average common equity (RCE) to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent. Prior to June 28, 2010, the APSC provided for accretions to the ESR of no more than $40,000 monthly until the maximum funding level was achieved, following a year in which a charge against the ESR was made. The APSC’s June 28, 2010, order approved Alagasco’s lower depreciation rates and approved standing authority for Alagasco to charge items to the ESR in excess of its funded balance and to allocate each year from the refundable negative salvage costs that are being refunded to customers over the nine year period the amount necessary to clear the debit balance in the ESR each September 30, subject to APSC-approved guidelines. The APSC also approved the amortization of the ESR into rates over a five year period in cases where the ESR is unfunded or underfunded, subject to APSC-approved guidelines. As a result of these changes in the funding mechanism for the ESR, the APSC suspended the $40,000 per month accruals to the ESR during the nine year period when the refundable negative salvage costs are being refunded to customers.

Following a vote on September 7, 2010, the APSC, by order dated November 1, 2010, approved expansion of the ESR to include extraordinary O&M charges related to environmental response costs and to self insurance costs that exceed $1 million per occurrence. In addition, the APSC raised the thresholds on items that may be charged to the ESR as follows: (1) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single event that results in more than $275,000 of increased O&M; (2) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a combination of extraordinary O&M events that result in more than $412,500 of increased O&M; and (3) negative individual large commercial and industrial customer budget variances that exceed $350,000. Charges to the ESR relating to extraordinary O&M expenses can only be made when the Company’s year-end return on average common equity for RSE, not including the ESR charge, is below the midpoint of the APSC-approved return on equity range and only to the extent necessary to bring the RCE to the midpoint of the range. Charges to the ESR relating to negative individual large commercial and industrial customer revenue variances can only be made if such losses cause the RCE to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent, and then only to the extent necessary to bring the RCE up to the midpoint of the range. In the event that Alagasco’s RCE at September 30 of the related year is above the midpoint, any debit balance in the ESR shall remain in the ESR for recovery in subsequent years subject to the established guidelines. Additionally, the APSC, while confirming the five year amortization period established in the June 28, 2010, order for charges to the ESR in cases where the ESR is unfunded or underfunded, limited the amortization expense to $660,000 annually, with any excess amortization expense over $660,000 in any rate year being carried over and amortized in future rate years until full amortization of the ESR debit balance is complete. The APSC also raised the $40,000 per month accruals to $55,000 per month, but suspended the accruals pending further order of the APSC. Finally, the APSC established guidelines for the documentation, reporting and approval of rate recovery of items charged to the ESR.

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. 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 eleven of its active counterparties and in a net loss position with the remaining one at September 30, 2011. The four largest counterparty positions at September 30, 2011, Macquarie Bank Limited, J Aron & Company, Shell Energy North America (US), L.P. and Citibank, N.A. constituted approximately $35.8 million, $29.7 million, $23.5 million and $23.0 million, respectively, of Energen Resources’ net gain on fair value of derivatives. J.P. Morgan Ventures Energy Corporation was the only counterparty in a loss position of $0.2 million.

12

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2011, 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 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 accounting 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)	September 30, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	88,839			$	—		$	88,839
Long-term asset derivative instruments	67,461				—			67,461
Total derivative assets	156,300				—			156,300
Accounts receivable	(25,642		)	*	—			(25,642		)
Accounts payable	(1,298		)		—			(1,298		)
Long-term liability derivative instruments	(9,049		)	*	—			(9,049		)
Total derivative liabilities	(35,989		)		—			(35,989		)
Total derivatives designated	120,311				—			120,311
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	10,745				—			10,745
Long-term asset derivative instruments	42,482				—			42,482
Total derivative assets	53,227				—			53,227
Accounts payable	(40		)		(44,137		)	(44,177		)
Long-term liability derivative instruments	—				(13,050		)	(13,050		)
Total derivative liabilities	(40		)		(57,187		)	(57,227		)
Total derivatives not designated	53,187				(57,187		)	(4,000		)
Total derivatives	$	173,498			$	(57,187	)	$	116,311

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(in thousands)	December 31, 2010
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	85,867			$	—		$	85,867
Long-term asset derivative instruments	3,156			*	—			3,156
Total derivative assets	89,023				—			89,023
Accounts receivable	(25,315		)	*	—			(25,315		)
Accounts payable	(50,508		)		—			(50,508		)
Long-term liability derivative instruments	(83,631		)		—			(83,631		)
Total derivative liabilities	(159,454		)		—			(159,454		)
Total derivatives designated	(70,431		)		—			(70,431		)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable	(110		)		(27,906		)	(28,016		)
Long-term liability derivative instruments	—				(32,461		)	(32,461		)
Total derivative liabilities	(110		)		(60,367		)	(60,477		)
Total derivatives not designated	(110		)		(60,367		)	(60,477		)
Total derivatives	$	(70,541	)		$	(60,367	)	$	(130,908	)

* 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 $43.7 million deferred tax liability and a net $26.8 million deferred tax asset included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of September 30, 2011, and December 31, 2010, respectively.

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

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 September 30, 2011		Three months ended September 30, 2010
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of $105.7 million and ($4.4) million	—	$	172,430	$	(7,244	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	11,207	$	56,456
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	5,631	$	(1,861	)

(in thousands)	Location on Income Statement	Nine months ended September 30, 2011		Nine months ended September 30, 2010
Gain recognized in OCI on derivative (effective portion), net of tax of $76.6 million and $55.9 million	—	$	125,005	$	91,141
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	13,028	$	149,845
Gain recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	3,240	$	18

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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 September 30, 2011		Three months ended September 30, 2010
Gain (loss) recognized in income on derivative	Operating revenues	$	53,227	$	—
(in thousands)	Location on Income Statement	Nine months ended September 30, 2011		Nine months ended September 30, 2010
Gain (loss) recognized in income on derivative	Operating revenues	$	53,225	$	(4	)

As of September 30, 2011, $37.4 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 September 30, 2011, the Company had 3 thousand, 1,735 thousand, 3,108 thousand and 2,400 thousand barrels (MBbl) of oil hedges which expire during 2011, 2012, 2013 and 2014 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2013 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges.

Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	3.5 Bcf	$6.47 Mcf	NYMEX Swaps
	9.7 Bcf	$5.63 Mcf	Basin Specific Swaps
2012	11.0 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
2013	8.8 Bcf	$5.30 Mcf	NYMEX Swaps
	25.1 Bcf	$4.88 Mcf	Basin Specific Swaps
2014	3.0 Bcf	$5.72 Mcf	NYMEX Swaps
	16.8 Bcf	$5.16 Mcf	Basin Specific Swaps
Oil
2011	1,334 MBbl	$83.73 Bbl	NYMEX Swaps
2012	6,282 MBbl	$87.40 Bbl	NYMEX Swaps
2013	6,827 MBbl	$89.31 Bbl	NYMEX Swaps
2014	5,612 MBbl	$90.56 Bbl	NYMEX Swaps
Oil Basis Differential
2011	854 MBbl	*	Basis Swaps
2012	3,124 MBbl	*	Basis Swaps
2013	2,768 MBbl	*	Basis Swaps
Natural Gas Liquids
2011	10.5 MMGal	$0.90 Gal	Liquids Swaps
2012	43.4 MMGal	$0.88 Gal	Liquids Swaps
2013	44.5 MMGal	$1.02 Gal	Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

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Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Description
2011	3.9 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

As of September 30, 2011, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014, and December 31, 2013, respectively.

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). 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.

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 New York Mercantile Exchange (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 liquids swaps.

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

	September 30, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	51,263		$	22,680		$	73,943
Noncurrent assets	84,700			16,475			101,175
Current liabilities	(42,806		)	(2,670		)	(45,476		)
Noncurrent liabilities	(13,050		)	(281		)	(13,331		)
Net derivative asset	$	80,107		$	36,204		$	116,311

	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Current liabilities	(76,527		)	(1,997		)	(78,524		)
Noncurrent liabilities	(107,452		)	(5,484		)	(112,936		)
Net derivative asset (liability)	$	(173,663	)	$	42,755		$	(130,908	)

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

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As of September 30, 2011, Alagasco had $44.1 million and $13.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities and noncurrent liabilities, respectively. As of December 31, 2010, Alagasco had $27.9 million and $32.5 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 September 30, 2011, and December 31, 2010.

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

	Three months ended			Three months ended
(in thousands)	September 30, 2011			September 30, 2010
Balance at beginning of period	$	13,446		$	91,817
Realized (gains) losses	1,088			(455		)
Unrealized gains relating to instruments held at the reporting date	32,235			26,282
Settlements during period	(10,565		)	(30,767		)
Balance at end of period	$	36,204		$	86,877

	Nine months ended			Nine months ended
(in thousands)	September 30, 2011			September 30, 2010
Balance at beginning of period	$	42,755		$	64,517
Realized (gains) losses	1,088			(455		)
Unrealized gains relating to instruments held at the reporting date	28,681			102,169
Settlements during period	(36,320		)	(79,354		)
Balance at end of period	$	36,204		$	86,877

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended					Three months ended
(in thousands, except per share amounts)	September 30, 2011					September 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	87,599	72,068	$	1.22	$	38,304	71,854	$	0.53
Effect of dilutive securities
Stock options			298					199
Non-vested restricted stock			9					17
Diluted EPS	$	87,599	72,375	$	1.21	$	38,304	72,070	$	0.53

	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2011					September 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	245,192	72,045	$	3.40	$	210,557	71,838	$	2.93
Effect of dilutive securities
Stock options			355					206
Non-vested restricted stock			9					17
Diluted EPS	$	245,192	72,409	$	3.39	$	210,557	72,061	$	2.92

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For the three months and nine months ended September 30, 2011, the Company had 293,978 options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months and nine months ended September 30, 2010, the Company had 479,820 options that were excluded from the computation of diluted EPS. For the three months and nine months ended September 30, 2011 and 2010, the Company had no 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						Nine months ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Operating revenues
Oil and gas operations	$	318,952		$	234,111		$	779,834		$	706,311
Natural gas distribution	59,616			61,693			415,497			498,132
Total	$	378,568		$	295,804		$	1,195,331		$	1,204,443
Operating income (loss)
Oil and gas operations	$	161,331		$	76,644		$	351,808		$	289,385
Natural gas distribution	(10,681		)	(9,015		)	65,541			69,378
Eliminations and corporate expenses	(238		)	(309		)	(721		)	(952		)
Total	$	150,412		$	67,320		$	416,628		$	357,811
Other income (expense)
Oil and gas operations	$	(9,363	)	$	(4,848	)	$	(20,632	)	$	(17,274	)
Natural gas distribution	(4,162		)	(2,119		)	(10,115		)	(8,882		)
Eliminations and other	94			(463		)	182			(1,225		)
Total	$	(13,431	)	$	(7,430	)	$	(30,565	)	$	(27,381	)
Income before income taxes	$	136,981		$	59,890		$	386,063		$	330,430

(in thousands)	September 30, 2011		December 31, 2010
Identifiable assets
Oil and gas operations	$	3,752,437	$	3,160,601
Natural gas distribution	1,107,188		1,166,899
Eliminations and other	15,817		36,060
Total	$	4,875,442	$	4,363,560

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6. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended
	September 30,
(in thousands)	2011			2010
Net income	$	87,599		$	38,304
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $105.7 million and ($4.4) million	172,430			(7,244		)
Reclassification adjustment for derivative instruments, net of tax of ($6.4) million and ($20.7) million	(10,440		)	(33,849		)
Pension and postretirement plans, net of tax of ($5.6) million and ($3.6) million	(10,438		)	(6,678		)
Comprehensive income (loss)	$	239,151		$	(9,467	)

	Nine months ended
	September 30,
(in thousands)	2011			2010
Net income	$	245,192		$	210,557
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $76.6 million and $55.9 million	125,005			91,141
Reclassification adjustment for derivative instruments, net of tax of ($6.2) million and ($56.9) million	(10,085		)	(92,914		)
Pension and postretirement plans, net of tax of ($4.9) million and ($2.9) million	(9,073		)	(5,420		)
Comprehensive income	$	351,039		$	203,364

(in thousands)	September 30, 2011			December 31, 2010
Unrealized gain (loss) on hedges, net of tax of $43.7 million and ($26.8) million	$	71,253		$	(43,667	)
Pension and postretirement plans, net of tax of ($21.4) million and ($16.5) million	(39,803		)	(30,730		)
Accumulated other comprehensive income (loss)	$	31,450		$	(74,397	)

7. 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. On April 27, 2011, the Company amended the Stock Incentive Plan to increase the number of shares authorized for issuance by 3,000,000 shares. This increase resulted in 3,794,326 shares being available for future issuances. Options granted under the 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 293,978 non-qualified option shares during the first quarter of 2011 with a grant-date fair value of $19.65.

2004 Stock Appreciation Rights Plan

The Energen 2004 Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 189,984 awards during the first quarter of 2011. These awards had a fair value of $10.27 as of September 30, 2011.

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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 2011, Energen Resources awarded 6,314 Petrotech units with a three-year vesting period. These awards had a fair value of $39.70 as of September 30, 2011.

1997 Deferred Compensation Plan

During the three months and nine months ended September 30, 2011, the Company had noncash purchases of approximately $16,000 and $0.4 million, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

8. EMPLOYEE BENEFIT PLANS

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	2,293		$	2,144		$	6,879		$	6,430
Interest cost	2,740			2,841			8,220			8,524
Expected long-term return on assets	(3,868		)	(3,229		)	(11,603		)	(9,686		)
Actuarial loss	1,609			1,443			4,826			4,330
Prior service cost amortization	124			124			372			372
Net periodic expense	$	2,898		$	3,323		$	8,694		$	9,970

The Companyanticipates required contributions of approximately $7.2 million during 2011 to the 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 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 2011. For the three months and nine months ending September 30, 2011, the Company made benefit payments aggregating $36,000 and $2.2 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $36,000 through the remainder of 2011.

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	442		$	516		$	1,327		$	1,548
Interest cost	1,111			1,208			3,332			3,625
Expected long-term return on assets	(1,104		)	(996		)	(3,314		)	(2,990		)
Transition amortization	479			479			1,438			1,438
Net periodic expense	$	928		$	1,207		$	2,783		$	3,621

For the three months and nine months ended September 30, 2011, the Company made contributions aggregating $0.9 million and $2.8 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $0.9 million to postretirement benefit plan assets through the remainder of 2011. During the first quarter of 2010, the Company recognized $128,000 in income tax expense resulting from a reduction in deferred tax asset related to changes in the tax treatment for the Medicare Part D subsidy under the recently enacted health care reform legislation.

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9. 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 $116 million through September 2024. During the nine months ending September 30, 2011 and 2010, Alagasco recognized approximately $36.8 million and $38.1 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 210 million Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2011, the fixed price purchases under these guarantees had a maximum term outstanding through October 2012 and an aggregate purchase price of $3.7 million with a market value of $3.4 million.

Energen Resources entered into three agreements which commence 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 terminates the agreements prior to the commencement dates, Energen Resources' total resulting exposure is the greater of approximately $2.2 million or all expenses incurred in the preparation of the subject rigs for the operations contemplated by the contract. Upon commencement, Energen Resources' total resulting exposure could be as much as $34 million depending on the contractors ability to remarket the drilling rig.

Income Taxes: Energen and its subsidiaries' 2007 and 2008 federal consolidated income tax returns have been under Internal Revenue Service (IRS) examination. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco was allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns. The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.

During the current year-to-date, the Company recognized a $2.1 million income tax benefit related to changes in Alabama state income tax laws. In addition, the Company recognized a $1.5 million net benefit for the release of the unrecognized income tax benefit liability due to the Company's settlement with the IRS discussed above. These benefits are partially offset by $2.1 million of income tax expense for additional unrecognized tax benefit liabilities. 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 $2.4 million during the nine months ended September 30, 2011.

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 manufactured gas distribution sites (one of which it still owns). Subject to the following paragraph discussing the Huntsville, Alabama manufactured gas plant site, an investigation of the sites does not indicate the present need for 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.

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In June 2009, Alagasco received a General Notice Letter from the United States Environmental Protection Agency (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, developed an action plan for the site and as of June 30, 2011, had substantially completed the action plan. Based on information available at this time, Alagasco estimates that it will incur costs associated with the site of approximately $4.8 million, including costs previously incurred. During the three months and nine months ended September 30, 2011, the Company incurred costs of $0.6 million and $3.6 million, respectively, associated with the site. As of September 30, 2011, the Company has accrued a contingent liability of $0.6 million in addition to the costs previously incurred. If it is determined that further work is appropriate or required by the EPA, then actual costs will likely exceed the estimate. Alagasco expects to recover such costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account of which the remaining 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 $20 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 Department's findings and the ONRR Order. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2011.

10. FINANCIAL INSTRUMENTS

In August 2011, the Company issued $400 million of Senior Notes with an interest rate of 4.625% percent due September 1, 2021. The long-term debt proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.

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 $860.3 million and has a carrying value of $805.4 million at September 30, 2011. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $221.9 million and has a carrying value of $200.4 million at September 30, 2011. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2011, and December 31, 2010, Alagasco’s finance receivable totaled $10.2 million and $8.8 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 $428,000 as of September 30, 2011.

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

(in thousands)
Allowance for credit losses as of December 31, 2010	$	447
Provision	(24		)
Allowance for credit losses as of September 30, 2011	$	423

11. REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	September 30, 2011				December 31, 2010
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	87,181	$	132	$	60,284
Accretion and depreciation for asset retirement obligation	—		9,007		—		8,681
Risk management activities	44,137		13,050		27,906		32,461
RSE adjustment	25		—		25		—
Enhanced stability reserve	—		—		—		3,794
Other	193		6		223		145
Total regulatory assets	$	44,525	$	109,244	$	28,286	$	105,365
Regulatory liabilities:
RSE adjustment	$	5,068	$	—	$	4,147	$	—
Unbilled service margin	5,143		—		34,197		—
Postretirement liabilities	—		—		—		754
Gas supply adjustment	21,060		—		14,990		—
Asset removal costs, net	—		7,834		—		6,913
Refundable negative salvage	20,545		67,237		22,336		90,504
Asset retirement obligation	—		11,697		—		11,439
Other	33		811		33		837
Total regulatory liabilities	$	51,849	$	87,579	$	75,703	$	110,447

12. ASSET RETIREMENT OBLIGATIONS

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

During the nine months ended September 30, 2011, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2010	$	97,415
Liabilities incurred	3,761
Liabilities settled	(1,531		)
Accretion expense	5,066
Balance of ARO as of September 30, 2011	$	104,711

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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 $11.7 million and $11.4 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of September 30, 2011, and December 31, 2010, respectively. The conditional asset retirement obligations reflect the re-estimation of removal costs associated with Alagasco’s revised depreciation rate. 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 liabilities for accumulated asset removal costs of $7.8 million and $6.9 million for September 30, 2011, and December 31, 2010, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets. As of September 30, 2011, the Company recognized $20.5 million and $67.2 million of refundable negative salvage as regulatory liabilities in current liabilities and deferred credit and other liabilities, respectively, on the balance sheet in response to the June 28, 2010, APSC order.

13. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

In October 2011, Energen signed a purchase and sale agreement to buy interests in certain liquids-rich properties in the Permian Basin for a cash purchase price of $158 million (subject to closing adjustments). This sale is expected to close during the fourth quarter and will have an effective date of August 1, 2011. Energen will acquire total proved reserves of approximately 13.8 million barrels of oil equivalents (MMBOE). Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the acquisition proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 percent. Energen Resources will use its credit facilities and internally generated cash flows to finance the acquisition.

Energen signed a purchase and sale agreement in October 2011 to buy interests in certain properties in the Permian Basin for a cash purchase price of $54 million (subject to closing adjustments). This sale is expected to close during the fourth quarter and will have an effective date of July 1, 2011. Energen will acquire total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the acquisition proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 percent. Energen Resources will use its credit facilities and internally generated cash flows to finance the acquisition.

In July 2011, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $22 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.

On December 15, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $74 million. This purchase had an effective date of December 1, 2010. Energen acquired proved reserves of approximately 7.6 MMBOE. Of the proved reserves acquired, an estimated 92 percent are undeveloped. Approximately 62 percent of the acquisition’s estimated proved reserves are oil, 24 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 December 15, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,066
Unproved leasehold properties	32,500
Accounts receivable	143
Asset retirement obligation	(79		)
Total identifiable net assets	$	73,630

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Included in the Company’s consolidated results of operations for the nine months ended September 30, 2011, are $6.8 million of operating revenues and $3.2 million in operating income resulting from the operation of the properties acquired above.

On December 9, 2010, Energen completed the asset purchase of certain liquids-rich properties in the Permian Basin from SandRidge Energy, Inc. for a cash purchase price of $103 million (subject to closing adjustments). This purchase had an effective date of December 9, 2010. Energen acquired no proved reserves related to this acquisition. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

On September 30, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash price of $188 million. This purchase had an effective date of September 1, 2010. Energen acquired proved reserves of approximately 18 MMBOE. Of the proved reserves acquired, an estimated 89 percent are undeveloped. Approximately 65 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 13 percent. Energen Resources used its 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 September 30, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	188,314
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,747
Unproved leasehold properties	35,360
Accounts receivable	1,461
Asset retirement obligation	(142		)
Accounts payable	(112		)
Total identifiable net assets	$	188,314

Included in the Company’s consolidated results of operations for the nine months ended September 30, 2011, are $32.8 million of operating revenues and $16.2 million in operating income resulting from the operation of the properties acquired above.

14. RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. These amendments require that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company is currently evaluating the impact of the ASU.

In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): 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. The Company is currently evaluating the impact of the ASU.

In July 2010, the FASB issued ASU No. 2010-20, Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses. These disclosures, as of the end of a reporting period, are effective for the interim and annual reporting periods ending on or after December 15, 2010. The disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The disclosures required under this standard have been included in Note 10, Financial Instruments.

On January 1, 2010, the Company adopted Accounting Standard Update (ASU) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures About Fair Value Measurements. These disclosures are effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The disclosures required under this standard have been 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 $87.6 million ($1.21 per diluted share) for the three months ended September 30, 2011 compared with net income of $38.3 million ($0.53 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 September 30, 2011, of $96.8 million as compared with $46.3 million in the same quarter in the previous year. This increase in net income was primarily a result of significantly higher oil and natural gas liquids commodity prices (approximately $12 million after-tax), an after-tax $33.1 million non-cash mark-to-market gain on derivatives, increased production volumes (approximately $23 million after-tax) and decreased exploration expense (approximately $15 million after-tax) largely due to a 2010 non-cash write-off of $14.6 million after-tax of unproved leasehold costs associated with Alabama shale acreage combined with a related $6.7 million after-tax write-off of well costs. Negatively affecting net income was the impact of lower natural gas commodity prices (approximately $14 million after-tax), higher depreciation, depletion and amortization (DD&A) expense (approximately $7 million after-tax), increased lease operating expense excluding production taxes (approximately $4 million after-tax) and increased production taxes (approximately $2 million after-tax). Energen's natural gas utility, Alagasco, reported a net loss of $9.1 million in the third quarter of 2011 compared to a net loss of $7.1 million in the same period last year. This decrease largely reflects the timing of rate recovery under Alagasco’s rate-setting mechanisms partially offset by 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.

For the 2011 year-to-date, Energen's net income totaled $245.2 million ($3.39 per diluted share) compared to net income of $210.6 million ($2.92 per diluted share) for the same period in the prior year. Energen Resources generated net income for the nine months ended September 30, 2011, of $209.6 million as compared with $174.7 million in the previous period. Increased production volumes (approximately $46 million after-tax), higher oil and natural gas liquids commodity prices (approximately $12 million after-tax), an after-tax $33.1 million non-cash mark-to-market gain on derivatives and lower exploration expense (approximately $26 million after-tax) largely due to the non-cash $24.6 million after-tax Alabama shale acreage write-off in 2010 combined with the related $8.6 million after-tax write-off of well costs and the $3.6 million after-tax gain on the sale of properties in the Permian Basin were partially offset by lower natural gas commodity prices (approximately $47 million after-tax), higher DD&A expense (approximately $12 million after-tax), increased lease operating expense excluding production taxes (approximately $10 million after-tax), increased production taxes (approximately $6 million after-tax) and increased administrative expense (approximately $4 million after-tax). Alagasco’s net income of $35.3 million in the current year-to-date compared to net income of $36.8 million in the same period in the previous year primarily due to the timing of rate recovery under Alagasco’s rate-setting mechanisms largely offset by 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.

Oil and Gas Operations

Revenues from oil and gas operations rose 36.2 percent to $319.0 million for the three months ended September 30, 2011, and 10.4 percent to $779.8 million in the year-to-date primarily as a result of higher production volumes and increased realized oil and natural gas liquids commodity prices partially offset by decreased realized natural gas commodity prices. During the current quarter, revenue per unit of production for natural gas decreased 19.3 percent to $5.43 per thousand cubic feet (Mcf), while oil revenue per unit of production rose 10.1 percent to $84.56 per barrel. Natural gas liquids revenue per unit of production increased 28.2 percent to an average price of $1.00 per gallon. In the year-to-date, revenue per unit of production for natural gas decreased 20.7 percent to $5.49 per Mcf, oil revenue per unit of production increased 2.7 percent to $80.17 per barrel and natural gas liquids revenue per unit of production rose 17.3 percent to an average price of $0.95 per gallon. As detailed under Selected Business Segment Data, 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 both the current quarter and year-to-date increased largely due to higher volumes related to the September 2010 and December 2010 purchases of certain Permian Basin liquids-rich properties and field development partially offset by normal production declines. Natural gas production in the third quarter rose slightly to 17.8 billion cubic feet (Bcf), oil volumes increased 32.5 percent to 1,709 thousand barrels (MBbl) and natural gas liquids production rose 22.7 percent to 24.3 million gallons (MMgal). For the year-to-date, natural gas production increased slightly to 52.9 Bcf, while oil volumes rose 22.5 percent to 4,574 MBbl. Natural gas liquids production increased 15.6 percent to 66.6 MMgal. Natural gas comprised approximately 56 percent and 59 percent of Energen Resources' production for the current quarter and the year-to-date, respectively.

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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 no property sales in the third quarter of 2011 and 2010. In the current year-to-date, Energen Resources recorded a pre-tax gain of $5.8 million primarily from the sale of certain properties in the Permian Basin. During the nine months ended September 30, 2010, Energen Resources recorded a pre-tax gain of $0.6 million largely from the sale of certain property in the Black Warrior Basin.

Operations and maintenance (O&M) expense decreased $15.3 million for the quarter and $18.5 million in the year-to-date. Lease operating expense (excluding production taxes) increased $7.2 million for the quarter largely due to additional workover and repair expense (approximately $2.6 million), the September and December 2010 acquisitions of Permian Basin liquids-rich properties (approximately $2.5 million), increased labor costs (approximately $0.9 million) and higher marketing and transportation costs (approximately $0.7 million). In the year-to-date, lease operating expense (excluding production taxes) increased $16.3 million primarily due to the 2010 acquisitions (approximately $5.3 million), increased workover and repair expense (approximately $4.3 million), higher marketing and transportation costs (approximately $1.5 million), increased labor costs (approximately $1.4 million), additional ad valorem taxes (approximately $1.3 million), increased nonoperated costs (approximately $0.7 million) and higher gathering system expense (approximately $0.6 million). Administrative expense increased $1.2 million for the three months ended September 30, 2011 largely due to increased legal expenses (approximately $2.5 million) partially offset by decreased costs from the Company’s performance-based compensation plans (approximately $1.6 million). For the nine months ended September 30, 2011, administrative expense rose $7.1 million primarily due to higher costs related to the Company’s performance-based compensation plans (approximately $2.2 million), increased legal expenses (approximately $1.6 million) and increased labor costs (approximately $1.5 million). Exploration expense fell $23.7 million in the third quarter of 2011 and $41.8 million year-to-date. In the third quarter of 2011, Energen Resources recorded a write-off of a well in the Permian Basin for $9.9 million pre-tax. In the third quarter of 2010, Energen Resources incurred a non-cash write-off of $23.4 million pre-tax of unproved capitalized leasehold costs associated with the remainder of its Alabama shale leasehold. In the second quarter of 2010, Energen Resources recorded a non-cash write-off of $16.1 million pre-tax of unproved leasehold associated with the deep Conasauga shale acreage. During the three months and nine months ended September 30, 2010, Energen Resources also recorded $10.8 million and $13.8 million, respectively, in write-offs of well costs related to Alabama shale leasehold.

Energen Resources' DD&A expense for the quarter rose $11.5 million and increased $19.3 million year-to-date. The average depletion rate for the current quarter was $11.78 per barrel of oil equivalent (BOE) as compared to $10.70 per BOE in the same period a year ago. For the nine months ended September 30, 2011, the average depletion rate was $11.15 per BOE as compared to $10.64 per BOE in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $5.6 million and $7.6 million, respectively, to the increase in DD&A expense, was largely due to higher rates resulting from the acquisition of properties and an increase in development costs. Higher production volumes contributed approximately $5.8 million and $11.5 million to the increase in DD&A expense for the quarter and year-to-date.

Energen Resources' expense for taxes other than income taxes was $3.9 million and $9.7 million higher in the three months and nine months ended September 30, 2011, largely due to production-related taxes. In the current quarter and year-to-date, higher commodity market prices contributed approximately $2.7 million and $7.4 million, respectively, to the increase in production-related taxes. Also increasing production-related taxes were higher natural gas, oil and natural gas liquid production volumes which contributed approximately $1.2 million and $2.4 million, respectively, for the quarter and year-to-date. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues decreased $2.1 million for the quarter largely due to a decline in customer usage combined with adjustments from the utility’s rate setting mechanisms. During the third quarter of 2011, Alagasco had a $1.2 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. For the third quarter, weather was comparable with the same quarter in the prior year. Residential sales volumes fell 1.1 percent while commercial and industrial customer sales volumes rose 2.3 percent. Transportation volumes decreased 7.2 percent in period comparisons. Revenues for the year-to-date fell $82.6 million primarily due to lower gas costs and decreased customer usage along with adjustments for rate-setting purposes. In the current year-to-date, Alagasco had reduction in revenues of $6.7 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. In the 2010 year-to-date, Alagasco had reduction in revenues of $10.6 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. Weather, for the current nine months, that was 18 percent warmer compared with the same period in the prior year contributed to a 15 percent decrease in residential sales volumes and a 10.2 percent fall in commercial and industrial customer sales volumes. Transportation volumes decreased 1 percent in period comparisons. A decrease in gas purchase volumes partially offset by higher gas costs resulted in a 3.6 percent decrease in cost of gas for the quarter. For the year-to-date, a decrease in gas purchase volumes combined with lower gas costs contributed to a 29.3 percent decrease in cost of gas. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco's rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco's tariff provides a temperature adjustment mechanism, also included

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in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense decreased 2.3 percent in the current quarter primarily due to lower bad debt expense (approximately $2.7 million) largely due to improved collection efforts partially offset by increased distribution operation expenses (approximately $0.9 million). In the nine months ended September 30, 2011, O&M expense rose 8 percent primarily due to higher marketing expenses (approximately $2.4 million), increased distribution operation expenses (approximately $2.3 million), increased labor-related costs (approximately $1.9 million) and increased consulting and technology costs (approximately $0.9 million). For the year-to-date, the decrease to bad debt expense in the current quarter was offset by the increase to bad debt expense (approximately $2.9 million) which is attributable to the prior year correction of a $3 million error identified by Alagasco during the first quarter of 2010 in the calculation of the estimate of the allowance for doubtful accounts as of December 31, 2009. See Note 1, Basis of Presentation, in the Notes to Unaudited Condensed Financial Statements for further discussion.

A 5.6 percent increase in depreciation expense in the current quarter was primarily due to the extension and replacement of the utility's distribution system and replacement of its support systems. Depreciation expense decreased 13.9 percent in the year-to-date primarily due to revised depreciation rates effective June 1, 2010, partially offset by the extension and replacement of the utility's distribution system and replacement of its support systems. The revised depreciation rates decreased depreciation expense by approximately $6.8 million for the nine months ended September 30, 2011, respectively, from expense amounts calculated using the prior depreciation rate. On June 28, 2010, the Alabama Public Service Commission (APSC) approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the five years prior to the approval of the reduction in depreciation rates. Approved depreciation rates averaged approximately 3.1 percent and 3.8 percent in the nine months ended September 30, 2011 and 2010, respectively.

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 $2.4 million in the third quarter of 2011 and $1.5 million year-to-date largely due to increased short-term borrowings and the issuance of $400 million of Senior Notes by Energen in August 2011 with an interest rate of 4.625 percent due September 1, 2021 partially offset by the repayment of $150 million of medium-term notes with an interest rate of 7.625 percent in December 2010. Income tax expense for the Company increased $27.8 million and $21 million in the current quarter and year-to-date. respectively, largely due to higher pre-tax income. During the year-to-date, the Company recognized a $2.1 million income tax benefit related to changes in Alabama state income tax laws. In addition, the Company recognized a $1.5 million net benefit for the release of the unrecognized income tax benefit liability due to the Company's settlement with the Internal Revenue Service (IRS) which allowed Alagasco the full repair tax deductions as originally claimed for its gas distribution property in 2007 and 2008. These benefits are partially offset by $2.1 million of income tax expense for additional unrecognized tax benefit liabilities.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $593.9 million as compared to $517.9 million in the prior period. Net income increased during period comparisons primarily due to increased production volumes and higher realized oil and natural gas liquids realized commodity prices partially offset by lower natural gas realized commodity prices at Energen Resources. Deferred income taxes increased in the current year due to the tax effect of higher 2011 capital expenditures and the 2011 impact of bonus depreciation. 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 and changes to storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $734.6 million for the nine months ended September 30, 2011 primarily due to additions of property, plant and equipment of $741 million. Energen Resources incurred on a cash basis $683.4 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. Utility capital expenditures on a cash basis totaled $57.4 million year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities.

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The Company provided net cash of $139.3 million from financing activities in the year-to-date primarily due to the August 2011 issuance by Energen of $400 million in Senior Notes with an interest rate of 4.625 percent due September 1, 2021 and the issuance of common stock through the Stock Incentive Plan partially offset by a decrease in short-term borrowings and 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 2011, the Company expects its oil and gas capital spending to total approximately $1.2 billion, including $238 million for certain property acquisitions in the Permian Basin, $657 million for existing properties, $182 million for exploration and $66 for unproved leasehold acquisitions. In October 2011, Energen signed a purchase and sale agreement to buy interests in certain liquids-rich properties in the Permian Basin for a cash purchase price of $158 million (subject to closing adjustments). This sale is expected to close during the fourth quarter and will have an effective date of August 1, 2011. Energen will acquire total proved reserves of approximately 13.8 million barrels of oil equivalents (MMBOE). Of the proved reserves acquired, an estimated 76 percent are undeveloped. Energen also signed a purchase and sale agreement in October 2011 to buy interests in certain properties in the Permian Basin for a cash purchase price of $54 million (subject to closing adjustments). This sale is expected to close during the fourth quarter and will have an effective date of July 1, 2011. Energen will acquire total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Capital investment at Energen Resources in 2012 and 2013 is expected to approximate $900 million and $855 million, respectively, including the acquisitions discussed above. These estimates are subject to revision as Energen Resources completes its formal budgeting process for 2012 and 2013.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions, except as disclosed above, are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company issued $400 million in Senior Notes with an interest rate of 4.625 percent in August 2011. The Company currently has no plans for the issuance of equity.

Natural Gas Distribution

Alagasco is subject to regulation by the APSC and is allowed to earn a range of return on average 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 $20.3 million and $2.7 million for the period January through September 2011 and in December 2010, respectively. Alagasco anticipates refunding approximately $20.5 million of refundable negative salvage costs through lower tariff rates over the next twelve months. An additional estimated $67.2 million of refundable negative salvage costs will be refunded to eligible customers on a declining basis through lower tariff rates over an eight year period beginning December 1, 2011. The total amount refundable to customers is subject to adjustments over the entire nine year period for charges made to the 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, environmental response costs, and self insurance costs above $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, subject to APSC review guidelines. The refunds as of December 2010 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 annually despite above-average levels of penetration along existing distribution lines. To increase its customer base, the utility is capitalizing on opportunities to expand its distribution lines to areas with economic growth potential and to acquire municipally owned gas systems in Alabama. 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.

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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 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 $35 million in 2011 but will vary depending upon the price of natural gas. During both 2011 and 2012, Alagasco plans to invest an estimated $75 million in utility capital expenditures for normal distribution and support systems and 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. Alagasco has received approval from the APSC for an issuance of up to $50 million of long-term debt.

Weather Event

On April 27, 2011, severe weather including a number of deadly tornados caused significant damage to several communities in Alabama served by Alagasco. These communities included Tuscaloosa, Pleasant Grove, Hueytown and parts of Birmingham. Alagasco experienced an approximate 2,400 decrease in residential customers due to the impact of these storms, however, earnings and cash flows have not been affected materially during the three months or nine months ended September 30, 2011. Energen Resources was not impacted materially by the storms.

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 September 30, 2011, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with eleven of its active counterparties and in a net loss position with the remaining one at September 30, 2011. 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. 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.

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Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	3.5 Bcf	$6.47 Mcf	NYMEX Swaps
	9.7 Bcf	$5.63 Mcf	Basin Specific Swaps
2012	11.0 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
2013	8.8 Bcf	$5.30 Mcf	NYMEX Swaps
	25.1 Bcf	$4.88 Mcf	Basin Specific Swaps
2014	3.0 Bcf	$5.72 Mcf	NYMEX Swaps
	16.8 Bcf	$5.16 Mcf	Basin Specific Swaps
Oil
2011	1,334 MBbl	$83.73 Bbl	NYMEX Swaps
2012	6,282 MBbl	$87.40 Bbl	NYMEX Swaps
2013	6,827 MBbl	$89.31 Bbl	NYMEX Swaps
2014	5,612 MBbl	$90.56 Bbl	NYMEX Swaps
Oil Basis Differential
2011	854 MBbl	*	Basis Swaps
2012	3,124 MBbl	*	Basis Swaps
2013	2,768 MBbl	*	Basis Swaps
Natural Gas Liquids
2011	10.5 MMGal	$0.90 Gal	Liquids Swaps
2012	43.4 MMGal	$0.88 Gal	Liquids Swaps
2013	44.5 MMGal	$1.02 Gal	Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Description
2011	3.9 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

Alagasco has not entered into any new cash flow derivative transactions on its gas supply in the past 18 months. 

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.

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

	September 30, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	51,263		$	22,680		$	73,943
Noncurrent assets	84,700			16,475			101,175
Current liabilities	(42,806		)	(2,670		)	(45,476		)
Noncurrent liabilities	(13,050		)	(281		)	(13,331		)
Net derivative asset (liability)	$	80,107		$	36,204		$	116,311

	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Current liabilities	(76,527		)	(1,997		)	(78,524		)
Noncurrent liabilities	(107,452		)	(5,484		)	(112,936		)
Net derivative asset (liability)	$	(173,663	)	$	42,755		$	(130,908	)

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

As of September 30, 2011, Alagasco had $44.1 million and $13.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities and noncurrent liabilities, respectively. As of December 31, 2010, Alagasco has $27.9 million and $32.5 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 September 30, 2011 and December 31, 2010.

Level 3 assets and liabilities as of September 30, 2011, represent an immaterial amount of total assets and liabilities. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $39 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations for Level 3 derivatives would be immaterial due to derivative instruments designated as cash flow hedges. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

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 nine months ended September 30, 2011. 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 nine months ended September 30, 2011, the Company had noncash purchases of approximately $0.7 million 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. These syndicated credit facilities replace the majority of the Company’s short-term credit facilities which were available to Energen and Alagasco. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of 65 percent for each of the Company and Alagasco. The Company currently has available credit facilities as follows:

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(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	5/23/2012	-		10,000		10,000
Total		$	850,000	$	169,000	$	1,019,000

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, the recovery and pass-through of regulatory items and the seasonality of Alagasco's business. Energen's accounts receivable and accounts payable at September 30, 2011 include $73.9 million and $45.5 million, respectively, associated with its derivative financial instruments. Working capital at Alagasco reflects an expected pass-through to rate payers of $21.1 million associated with the timing of recovery for the cost of gas supply and of $20.5 million in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates.

Energen and Alagasco rely upon excess cash flow 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.

Dividends

Energen expects to pay annual cash dividends of $0.54 per share on the Company’s common stock in 2011. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

Contractual Cash Obligations and Other Commitments

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, 2010.

Energen Resources entered into three agreements which commence 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 terminates the agreements prior to the commencement dates, Energen Resources' total resulting exposure is the greater of approximately $2.2 million or all expenses incurred in the preparation of the subject rigs for the operations contemplated by the contract. Upon commencement, Energen Resources' total resulting exposure could be as much as $34 million depending on the contractors ability to remarket the drilling rig.

Energen and its subsidiaries' 2007 and 2008 federal consolidated income tax returns have been under IRS examination. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco was allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns.  The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.

During 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 $20 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 Department's findings and the ONRR Order. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2011.

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Recent Accounting Standards Updates

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

FORWARD LOOKING STATEMENTS AND RISK FACTORS

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

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties 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 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, the recent adoption of financial reform legislation 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

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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, the recent adoption of financial reform legislation 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.

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					Nine months ended
	September 30,					September 30,
(in thousands, except sales price data)	2011			2010		2011			2010
Oil and Gas Operations
Operating revenues
Natural gas	$	96,604		$	119,287	$	290,240		$	365,302
Oil	197,636			99,045		419,830			291,543
Natural gas liquids	24,476			15,388		63,491			46,535
Other	236			391		6,273			2,931
Total	$	318,952		$	234,111	$	779,834		$	706,311
Production volumes
Natural gas (MMcf)	17,796			17,723		52,908			52,768
Oil (MBbl)	1,709			1,290		4,574			3,734
Natural gas liquids (MMgal)	24.3			19.8		66.6			57.6
Total production volumes (MMcfe)	31,518			28,295		89,868			83,401
Total production volumes (MBOE)	5,253			4,716		14,978			13,900
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	5.43		$	6.73	$	5.49		$	6.92
Oil (barrel)	$	115.64		$	76.80	$	91.79		$	78.09
Natural gas liquids (gallon)	$	1.01		$	0.78	$	0.95		$	0.81
Revenue per unit of production including effects of designated cash flow hedges
Natural gas (Mcf)	$	5.43		$	6.73	$	5.49		$	6.92
Oil (barrel)	$	84.56		$	76.80	$	80.17		$	78.09
Natural gas liquids (gallon)	$	1.00		$	0.78	$	0.95		$	0.81
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	4.11		$	4.03	$	4.10		$	4.40
Oil (barrel)	$	86.17		$	71.75	$	90.40		$	73.16
Natural gas liquids (gallon)	$	1.17		$	0.77	$	1.11		$	0.83
Other data
Lease operating expense (LOE)
LOE and other	$	54,563		$	47,405	$	152,220		$	135,965
Production taxes	14,367			10,475		40,842			31,062
Total	$	68,930		$	57,880	$	193,062		$	167,027
Depreciation, depletion and amortization	$	62,822		$	51,363	$	169,953		$	150,645
Capital expenditures	$	266,745		$	275,895	$	666,601		$	386,810
Exploration expenditures	$	10,775		$	34,506	$	12,596		$	54,367
Operating income	$	161,331		$	76,644	$	351,808		$	289,385
Natural Gas Distribution
Operating revenues
Residential	$	30,541		$	31,409	$	269,584		$	334,429
Commercial and industrial	16,984			17,130		107,283			128,216
Transportation	12,114			12,020		40,568			42,043
Other	(23		)	1,134		(1,938		)	(6,556		)
Total	$	59,616		$	61,693	$	415,497		$	498,132

36

Gas delivery volumes (MMcf)
Residential	1,385			1,401			16,725		19,673
Commercial and industrial	1,181			1,155			7,843		8,735
Transportation	10,004			10,783			33,713		33,988
Total	12,570			13,339			58,281		62,396
Other data
Depreciation and amortization	$	9,980		$	9,451		$	29,606	$	34,380
Capital expenditures	$	21,333		$	38,283		$	57,170	$	75,810
Operating income	$	(10,681	)	$	(9,015	)	$	65,541	$	69,378

37

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 September 30, 2011, 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 September 30, 2011, primarily relates to its syndicated credit facilities with variable interest rates. The weighted average interest rate for amounts outstanding at September 30, 2011 was 1.68 percent. All long-term debt obligations were at fixed rates.

38

ITEM 4. CONTROLS AND PROCEDURES

Energen Corporation

(a) Our disclosure controls and procedures 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 are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.

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

39

PART II: OTHER INFORMATION

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

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs**
July 1, 2011 through July 31, 2011	—		—		—	8,992,700
August 1, 2011 through August 31, 2011	—		—		—	8,992,700
September 1, 2011 through September 30, 2011	331	*	$	49.24	—	8,992,700
Total	331		$	49.24	—	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 5. OTHER INFORMATION

On November 2, 2011, the Company and Alagasco each entered into a first amendment (the "First Amendments"), to their respective syndicated revolving credit facilities dated October 29, 2010. The First Amendments give the Company and Alagasco additional flexibility to incur unsecured indebtedness outside of the existing credit facilities. Copies of the First Amendments are attached hereto as Exhibits 10(a) and 10(b) and are incorporated herein by this reference.

ITEM 6. EXHIBITS

10(a)	-	First Amendment to Credit Agreement, dated November 2, 2011, among Energen Corporation, certain of its subsidiaries, the lenders party thereto and Bank of America, N.A., as administrative agent
10(b)	-	First Amendment to Credit Agreement, dated November 2, 2011, among Alabama Gas Corporation, the lenders party thereto and Bank of America, N.A., as administrative agent
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 following financial statements from Energen Corporation's Quarterly Report on Form 10-Q for the quarter ended
		September 30, 2011, formatted in XBRL: (i) Consolidated Condensed Statements of Income,
		(ii) Consolidated Condensed Balance Sheets, (iii) Consolidated Condensed Statements of Cash Flows,
		(iv) the Notes to Unaudited Condensed Financial Statements.

40

SIGNATURES

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

		ENERGEN CORPORATION ALABAMA GAS CORPORATION
November 8, 2011	By	/s/ J. T. McManus, II
		J. T. McManus, II
		Chairman, Chief Executive Officer and President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation
November 8, 2011	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
November 8, 2011	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
November 8, 2011	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

41

EX-10.A

FIRST AMENDMENT TO CREDIT AGREEMENT

This FIRST AMENDMENT TO CREDIT AGREEMENT (this "Amendment") is entered

into and effective as of November 2, 2011 among ENERGEN CORPORATION, an Alabama

corporation (the "Borrower"), the Guarantors party hereto, the Lenders party hereto and BANK OF

AMERICA, N.A., as Administrative Agent (the "Administrative Agent"). Capitalized terms used

herein and not otherwise defined shall have the meanings set forth in the Credit Agreement (as

defined below).

RECITALS

WHEREAS, the Borrower, the Guarantors, the Lenders and the Administrative Agent are

party to that certain Credit Agreement dated as of October 29, 2010 (as amended and modified

from time to time, the "Credit Agreement");

WHEREAS, the Borrower has requested a revision to Section 8.09 of the Credit

Agreement; and

WHEREAS, the Required Lenders have agreed to such revision, subject to the terms set

forth herein, as more fully set forth below.

NOW THEREFORE, for good and valuable consideration, the receipt and sufficiency of

which are hereby acknowledged, the parties hereto agree as follows:

AGREEMENT

1. Amendment to Credit Agreement. Section 8.09 of the Credit Agreement is

amended and restated in its entirety to read as follows:

Other than those in existence as of the date of this Agreement as set forth on

Schedule 8.09, enter into, or permit to exist, any Contractual Obligation that encumbers

or restricts the ability of any such Person to (a) make Restricted Payments to any Loan

Party, (b) pay any Indebtedness or other obligation owed to any Loan Party, (c) make

loans or advances to any Loan Party, (d) transfer any of its property to any Loan Party,

(e) pledge its property pursuant to the Loan Documents or any renewals, refinancings,

exchanges, rejundings or extension thereof or (f) act as a Loan Party (unless prohibited by

Law) pursuant to the Loan Documents or any renewals, refinancings, exchanges,

refundings or extension thereof except (in respect of any of the matters referred to in

clauses (a)-(e) above) for (i) restrictions pursuant to this Agreement and the other Loan

Documents, (ii) restrictions in any document or instrument governing (x) Indebtedness

incurred pursuant to Sections 8.03(e)or 8.03(j)(provided that any such restriction

contained therein relates only to the asset or assets constructed or acquired in

connection therewith) and (y) other Indebtedness permitted by Section 8.03,(iii) any

Permitted Lien or any document or instrument governing any Permitted Lien; provided

that any such restriction contained therein relates only to the asset or assets subject to

such Permitted Lien or (iv) customary restrictions and conditions contained in any

agreement relating to the Disposition of any property permitted under Section 8.05

pending the consummation of such Disposition.

2. Effectiveness; Conditions Precedent. This Amendment shall be effective upon

receipt by the Administrative Agent of copies of this Amendment duly executed by the Borrower,

the Guarantors, the Administrative Agent and the Required Lenders.

3. Ratification of Credit Agreement. The term "Credit Agreement" as used in each

of the Loan Documents shall hereafter mean the Credit Agreement as amended and modified by

this Amendment. Except as herein specifically agreed, the Credit Agreement, as amended by this

Amendment, is hereby ratified and confirmed and shall remain in full force and effect according

to its terms. Each Loan Party acknowledges and consents to the modifications set forth herein

and agrees that this Amendment does not impair, reduce or limit any of its obligations under the

Loan Documents (including, without limitation, the indemnity obligations set forth therein),

except as such obligations are expressly modified by this Amendment, and that, after the date

hereof, this Amendment shall constitute a Loan Document.

4. Representations and Warranties. Each Loan Party represents and warrants as

follows:

(a) It has taken all necessary corporate action to authorize the execution,

delivery and performance of this Amendment.

(b) This Amendment has been duly executed and delivered by it and

constitutes its legal, valid and binding obligation, enforceable in accordance with its

terms except as enforceability may be limited by applicable bankruptcy, insolvency,

reorganization, moratorium or similar Debtor Relief Laws affecting the enforcement of

creditors' rights generally and by general equitable principles (whether enforcement is

sought by proceedings in equity or at law).

(c) No approval, consent, exemption, authorization, or other action by, or

notice to, or filing with, any Governmental Authority or any other Person is necessary or

required in connection with the execution, delivery or performance by it, or enforcement

against it, of this Amendment other than those that have already been obtained and are in

full force and effect.

(d) The execution and delivery of this Amendment by it has been duly

authorized by all necessary corporate action, and do not (a) contravene the terms of any

of its Organization Documents; (b) conflict with or result in any breach or contravention

of, or the creation of any Lien under, or require any payment to be made under (i) any

material Contractual Obligation to which it is a party or affecting it or its Properties or (ii)

any order, injunction, writ or decree of any Governmental Authority or any arbitral award

to which it or its property is subject; or (c) violate any material Law.

(e) The representations and warranties contained in Article VI applicable to

it are true and correct in all material respects on and as of the date hereof, except to the

extent that such representations and warranties specifically refer to an earlier date, in

which case they were true and correct as of such earlier date.

(f) No event has occurred and is continuing which constitutes a Default or

an Event of Default.

5. Counterparts/Telecopy. This Amendment may be executed in any number of

counterparts, each of which when so executed and delivered shall be an original, but all of which

shall constitute one and the same instrument. Delivery of executed counterparts of this

Amendment by telecopy or pdf. shall be effective as an original and shall constitute a

representation that an original shall be delivered promptly upon request.

6. GOVERNING LAW. THIS AMENDMENT AND THE RIGHTS AND

OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND

CONSTRUED AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE

OF NEW YORK.

IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of this Amendment to be duly executed and delivered and this Amendment shall be effective as of the date first above written.

BORROWER:

ENERGEN CORPORATION,

an Alabama corporation

By /s/ James T. McManus, II

Name: James T. McManus, II

Title: Chairman and Chief Executive Officer

By /s/ Charles W. Porter, Jr.

Name: Charles W. Porter, Jr.

Title: Vice President, Chief Financial Officer

          and Treasurer

GUARANTORS:

ENERGEN RESOURCES CORPORATION,

an Alabama corporation

By /s/ Charles W. Porter, Jr.

Name: Charles W. Porter, Jr.

Title: Vice President, Chief Financial Officer

          and Treasurer

ADMINISTRATIVE AGENT:

BANK OF AMERICA, N.A., as Administrative Agent

By /s/ Angelo M. Martorana

Name: Angelo M. Martorana

Title: Assistant Vice President

LENDERS:

BANK OF AMERICA, N.A., as a Lender

By /s/ Stephanie R. Pendleton

Name: Stephanie R. Pendleton

Title: Senior Vice President

Wells Fargo Bank, NA, as a Lender

By /s/ Paul V. Farrell

Name: Paul V. Farrell

Title: Director

Regions Bank, as a Lender

By /s/ David A. Simmons

Name: David A. Simmons

Title: Senior Vice President

COMPASS BANK, as a Lender

By /s/ Scott Brewer

Name: Scott Brewer

Title: Vice President

Mizuho Corporate Bank (USA), as a Lender

By /s/ Leon Mo

Name: Leon Mo

Title: Senior Vice President

SUMITOMO MITSUI BANKING CORPORATION, as a Lender

By /s/ Masakazu Hasegawa

Name: Masakazu Hasegawa

Title: Managing Director

US BANK, NATIONAL ASSOCIATION, as a Lender

By /s/ Kevin S. McFadden

Name: Kevin S. McFadden

Title: Vice President

THE BANK OF NOVA SCOTIA, as a Lender

By /s/ John Frazell

Name: John Frazell

Title: Director

CIBC Inc., as a Lender

By /s/ Trudy Nelson

Name: Trudy Nelson

Title: Authorized Signatory

By /s/ Richard Antl

Name: Richard Antl

Title: Authorized Signatory

PNC BANK, NATIONAL ASSOCIATION, as a Lender

By /s/ John Berry

Name: John Berry

Title: Vice President

TORONTO DOMINION (NEW YORK) LLC, as a Lender

By /s/ Kelly Hundal

Name: Kelly Hundal

Title: Authorized Signatory

The Northern Trust Company, as a Lender

By /s/ Sara Bravo

Name: Sara Bravo

Title: Second Vice President

BRANCH BANKING AND TRUST COMPANY, as a Lender

By /s/ Brantley Echols

Name: Brantley Echols

Title: Senior Vice President

Fifth Third Bank, as a Lender

By /s/ P. Ann Daniel

Name: P. Ann Daniel

Title: Relationship Manager

Land Bank of Taiwan Los Angeles Branch, as a Lender

By /s/ Juifu Chien

Name: Juifu Chien

Title: Vice President & General Manager

EX-10.B

FIRST AMENDMENT TO CREDIT AGREEMENT

This FIRST AMENDMENT TO CREDIT AGREEMENT (this "Amendment") is entered

into and effective as of November 2, 2011 among ALABAMA GAS CORPORATION, an

Alabama corporation (the "Borrower"), the Lenders party hereto and BANK OF AMERICA, N.A.,

as Administrative Agent (the "Administrative Agent"). Capitalized terms used herein and not

otherwise defined shall have the meanings set forth in the Credit Agreement (as defined below).

RECITALS

WHEREAS, the Borrower, the Lenders and the Administrative Agent are party to that

certain Credit Agreement dated as of October 29, 2010 (as amended and modified from time to

time, the "Credit Agreement");

WHEREAS, the Borrower has requested a revision to Section 8.09 of the Credit

Agreement; and

WHEREAS, the Required Lenders have agreed to such revision, subject to the terms set

forth herein, as more fully set forth below.

NOW THEREFORE, for good and valuable consideration, the receipt and sufficiency of

which are hereby acknowledged, the parties hereto agree as follows:

AGREEMENT

1. Amendment to Credit Agrreement. Section 8.09 of the Credit Agreement is

amended and restated in its entirety to read as follows:

Other than those in existence as of the date of this Agreement as set forth on

Schedule 8.09, enter into, or permit to exist, any Contractual Obligation that encumbers

or restricts the ability of any such Person to (a) make Restricted Payments to the

Borrower, (b) pay any Indebtedness or other obligation owed to the Borrower, (c) make

loans or advances to the Borrower, (d) transfer any of its property to the Borrower, (e)

pledge its property pursuant to the Loan Documents or any renewals, refinancings,

exchanges, refundings or extension thereof or (f) act as the Borrower (unless prohibited by

Law) pursuant to the Loan Documents or any renewals, refinancings, exchanges,

refundings or extension thereof, except (in respect of any of the matters referred to in

clauses (a)-(e) above) for (i) restrictions pursuant to this Agreement and the other Loan

Documents, (ii) restrictions in any document or instrument governing (x) Indebtedness

incurred pursuant to Sections 8.03(e) or 8.03(j) (provided that any such restriction

contained therein relates only to the asset or assets constructed or acquired in

connection therewith) and (y) other Indebtedness permitted by Section 8.03, (iii) any

Permitted Lien or any document or instrument governing any Permitted Lien; provided

that any such restriction contained therein relates only to the asset or assets subject to

such Permitted Lien or (iv) customary restrictions and conditions contained in any

agreement relating to the Disposition of any property permitted under Section 8.05

pending the consummation of such Disposition.

2. Effectiveness; Conditions Precedent. This Amendment shall be effective upon

receipt by the Administrative Agent of copies of this Amendment duly executed by the Borrower,

the Administrative Agent and the Required Lenders.

3. Ratification of Credit Agreement. The term "Credit Agreement" as used in each

of the Loan Documents shall hereafter mean the Credit Agreement as amended and modified by

this Amendment. Except as herein specifically agreed, the Credit Agreement, as amended by this

Amendment, is hereby ratified and confirmed and shall remain in full force and effect according

to its terms. The Borrower acknowledges and consents to the modifications set forth herein and

agrees that this Amendment does not impair, reduce or limit any of its obligations under the Loan

Documents (including, without limitation, the indemnity obligations set forth therein), except as

such obligations are expressly modified by this Amendment, and that, after the date hereof, this

Amendment shall constitute a Loan Document.

4. Representations and Warranties. The Borrower represents and warrants as

(a) It has taken all necessary corporate action to authorize the execution,

delivery and performance of this Amendment.

(b) This Amendment has been duly executed and delivered by it and

constitutes its legal, valid and binding obligation, enforceable in accordance with its

terms except as enforceability may be limited by applicable bankruptcy, insolvency,

reorganization, moratorium or similar Debtor Relief Laws affecting the enforcement of

creditors' rights generally and by general equitable principles (whether enforcement is

sought by proceedings in equity or at law).

(c) No approval, consent, exemption, authorization, or other action by, or

notice to, or filing with, any Governmental Authority or any other Person is necessary or

required in connection with the execution, delivery or performance by it, or enforcement

against it, of this Amendment other than those that have already been obtained and are in

full force and effect.

(d) The execution and delivery of this Amendment by it has been duly

authorized by all necessary corporate action, and do not (a) contravene the terms of any

of its Organization Documents; (b) conflict with or result in any breach or contravention

of, or the creation of any Lien under, or require any payment to be made under (i) any

material Contractual Obligation to which it is a party or affecting it or its Properties or (ii)

any order, injunction, writ or decree of any Governmental Authority or any arbitral award

to which it or its property is subject; or (c) violate any material Law.

(e) The representations and warranties contained in Article VI applicable to

it are true and correct in all material respects on and as of the date hereof, except to the

extent that such representations and warranties specifically refer to an earlier date, in

which case they were true and correct as of such earlier date.

(f) No event has occurred and is continuing which constitutes a Default or

an Event of Default.

5. Counterparts/Telecopy. This Amendment may be executed in any number of

counterparts, each of which when so executed and delivered shall be an original, but all of which

shall constitute one and the same instrument. Delivery of executed counterparts of this

Amendment by telecopy or pdf. shall be effective as an original and shall constitute a

representation that an original shall be delivered promptly upon request.

6. GOVERNING LAW. THIS AMENDMENT AND THE RIGHTS AND

OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND

CONSTRUED AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE

OF NEW YORK.

IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of this Amendment to be duly executed and delivered and this Amendment shall be effective as of the date first above written.

BORROWER:

ALABAMA GAS CORPORATION,

an Alabama corporation

By /s/ James T. McManus, II

Name: James T. McManus, II

Title: Chairman and Chief Executive Officer

By /s/ Charles W. Porter, Jr.

Name: Charles W. Porter, Jr.

Title: Vice President, Chief Financial Officer

          and Treasurer

ADMINISTRATIVE AGENT:

BANK OF AMERICA, N.A., as Administrative Agent

By /s/ Angelo M. Martorana

Name: Angelo M. Martorana

Title: Assistant Vice President

LENDERS:

BANK OF AMERICA, N.A., as a Lender

By /s/ Stephanie R. Pendleton

Name: Stephanie R. Pendleton

Title: Senior Vice President

Wells Fargo Bank, NA, as a Lender

By /s/ Paul V. Farrell

Name: Paul V. Farrell

Title: Director

Regions Bank, as a Lender

By /s/ David A. Simmons

Name: David A. Simmons

Title: Senior Vice President

COMPASS BANK, as a Lender

By /s/ Scott Brewer

Name: Scott Brewer

Title: Vice President

Mizuho Corporate Bank (USA), as a Lender

By /s/ Leon Mo

Name: Leon Mo

Title: Senior Vice President

SUMITOMO MITSUI BANKING CORPORATION, as a Lender

By /s/ Masakazu Hasegawa

Name: Masakazu Hasegawa

Title: Managing Director

US BANK, NATIONAL ASSOCIATION, as a Lender

By /s/ Kevin S. McFadden

Name: Kevin S. McFadden

Title: Vice President

SCOTIABANC INC., as a Lender

By /s/ J.F. Todd

Name: J.F. Todd

Title: Managing Director

CIBC Inc., as a Lender

By /s/ Trudy Nelson

Name: Trudy Nelson

Title: Authorized Signatory

By /s/ Richard Antl

Name: Richard Antl

Title: Authorized Signatory

PNC BANK, NATIONAL ASSOCIATION, as a Lender

By /s/ John Berry

Name: John Berry

Title: Vice President

TORONTO DOMINION (NEW YORK) LLC, as a Lender

By /s/ Kelly Hundal

Name: Kelly Hundal

Title: Authorized Signatory

THE NORTHERN TRUST COMPANY, as a Lender

By /s/ John Canty

Name: John Canty

Title: Senior Vice President

BRANCH BANKING AND TRUST COMPANY, as a Lender

By /s/ Brantley Echols

Name: Brantley Echols

Title: Senior Vice President

Fifth Third Bank, as a Lender

By /s/ P. Ann Daniel

Name: P. Ann Daniel

Title: Relationship Manager

Land Bank of Taiwan Los Angeles Branch, as a Lender

By /s/ Juifu Chien

Name: Juifu Chien

Title: Vice President & General Manager

EX-31.A

Exhibit 31(a)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

November 8, 2011	By	/s/ J. T. McManus, II
		Chairman, Chief Executive Officer and President of Energen Corporation

EX-31.B

Exhibit 31(b)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

November 8, 2011	By	/s/ Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation

EX-31.C

Exhibit 31(c)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

November 8, 2011	By	/s/ J. T. McManus, II
		Chairman and Chief Executive Officer of Alabama Gas Corporation

EX-31.D

Exhibit 31(d)

CERTIFICATION

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

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

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

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

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

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

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

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

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

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

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

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

November 8, 2011	By	/s/ Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Alabama Gas Corporation

EX-32.A

Exhibit 32(a)

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Energen Corporation (the “Registrant”) on Form 10-Q for the period ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of November 8, 2011

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

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

EX-32.B

Exhibit 32(b)

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Alabama Gas Corporation (the “Registrant”) on Form 10-Q for the period ended September 30, 2011, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to the registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of November 8, 2011

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

Consolidated Condensed Balance Sheets (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Current Assets
Cash and cash equivalents	$ 21,396	$ 22,659
Accounts receivable
Allowance for doubtful accounts	(13,596)	(15,048)
Accounts receivable, net of allowance for doubtful accounts of $13,596 at September 30, 2011, and $15,048 at December 31, 2010	214,553	286,849
Inventories
Storage gas inventory	42,856	36,706
Materials and supplies	28,424	19,045
Liquified natural gas in storage	3,515	3,551
Regulatory asset	44,525	28,286
Income tax receivable	5,142	44,489
Deferred income taxes	0	32,732
Prepayments and other	17,190	11,966
Total current assets	377,601	486,283
Property, Plant and Equipment
Oil and gas properties, successful efforts method	4,725,629	4,080,779
Less accumulated depreciation, depletion and amortization	1,316,643	1,161,635
Oil and gas properties, net	3,408,986	2,919,144
Utility plant	1,339,872	1,292,611
Less accumulated depreciation	528,313	509,989
Utility plant, net	811,559	782,622
Other property, net	23,423	17,461
Total property, plant and equipment, net	4,243,968	3,719,227
Other Assets
Regulatory asset	109,244	105,365
Pension and other postretirement assets	0	13,907
Long-term derivative instruments	101,175	0
Deferred charges and other	43,454	38,778
Total other assets	253,873	158,050
TOTAL ASSETS	4,875,442	4,363,560
Current Liabilities
Long-term debt due within one year	1,000	5,000
Notes payable to banks	75,000	305,000
Accounts payable	212,722	268,214
Accrued taxes	50,451	52,845
Customers' deposits	21,701	20,459
Amounts due customers	20,482	20,161
Accrued wages and benefits	30,150	25,203
Regulatory liability	51,849	75,703
Royalty payable	23,810	19,221
Deferred income taxes	2,004	0
Other	27,129	26,805
Total current liabilities	516,298	818,611
Long-term debt	803,829	405,254
Deferred Credits and Other Liabilities
Asset retirement obligation	104,711	97,415
Pension and other postretirement liabilities	71,025	36,551
Regulatory liability	87,579	110,447
Long-term derivative instruments	13,331	112,936
Deferred income taxes	785,826	615,084
Other	4,942	13,219
Total deferred credits and other liabilities	1,067,414	985,652
Commitments and Contingencies
Shareholders' Equity
Preferred stock, cumulative $0.01 par value	0	0
Common shareholders' equity
Common stock, $0.01 par value	750	748
Premium on capital stock	481,616	468,934
Capital surplus	2,802	2,802
Retained earnings	2,096,187	1,880,183
Accumulated other comprehensive loss, net of tax
Unrealized gain (loss) on hedges, net	71,253	(43,667)
Pension and postretirement plans	(39,803)	(30,730)
Deferred compensation plan	3,458	3,288
Treasury stock, at cost; 3,034,684 shares at September 30, 2011, and 3,024,847 shares at December 31, 2010	(128,362)	(127,515)
Total shareholders' equity	2,487,901	2,154,043
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	4,875,442	4,363,560
Alabama Gas Corporation
Current Assets
Cash and cash equivalents	6,754	16,910
Accounts receivable
Gas	45,246	136,800
Other	6,766	10,229
Affiliated companies	0	698
Allowance for doubtful accounts	(12,800)	(14,200)
Inventories
Storage gas inventory	42,856	36,706
Materials and supplies	4,206	4,147
Liquified natural gas in storage	3,515	3,551
Regulatory asset	44,525	28,286
Income tax receivable	3,508	10,315
Deferred income taxes	25,792	27,302
Prepayments and other	6,202	4,223
Total current assets	176,570	264,967
Property, Plant and Equipment
Utility plant	1,339,872	1,292,611
Less accumulated depreciation	528,313	509,989
Utility plant, net	811,559	782,622
Other property, net	43	43
Other Assets
Regulatory asset	109,244	105,365
Pension and other postretirement assets	0	9,201
Deferred charges and other	9,772	5,399
Total other assets	119,016	119,965
TOTAL ASSETS	1,107,188	1,167,597
Current Liabilities
Long-term debt due within one year	0	5,000
Notes payable to banks	50,000	70,000
Accounts payable	76,621	83,515
Affiliated Companies	370	0
Accrued taxes	29,006	48,476
Customers' deposits	21,701	20,459
Amounts due customers	20,482	20,161
Accrued wages and benefits	9,275	11,851
Regulatory liability	51,849	75,703
Other	9,150	11,822
Total current liabilities	268,454	346,987
Long-term debt	200,386	200,793
Deferred Credits and Other Liabilities
Pension and other postretirement liabilities	29,628	4,733
Regulatory liability	87,579	110,447
Long-term derivative instruments	13,050	32,461
Deferred income taxes	173,877	141,780
Other	734	3,077
Total deferred credits and other liabilities	304,868	292,498
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	298,976	292,815
Accumulated other comprehensive loss, net of tax
Total shareholders' equity	333,480	327,319
Total capitalization	533,866	528,112
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 1,107,188	$ 1,167,597

XML

Consolidated Condensed Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data	Sep. 30, 2011	Dec. 31, 2010
Current Assets
Allowance for doubtful accounts	$ 13,596	$ 15,048
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	74,991,804	74,786,376
Treasury stock, shares	3,034,684	3,024,847
Alabama Gas Corporation
Current Assets
Allowance for doubtful accounts	$ 12,800	$ 14,200
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

XML

Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2011

Statement of Income and Comprehensive Income [Abstract]

Schedule of Comprehensive Income (Loss)

	Three months ended
	September 30,
(in thousands)	2011			2010
Net income	$	87,599		$	38,304
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $105.7 million and ($4.4) million	172,430			(7,244		)
Reclassification adjustment for derivative instruments, net of tax of ($6.4) million and ($20.7) million	(10,440		)	(33,849		)
Pension and postretirement plans, net of tax of ($5.6) million and ($3.6) million	(10,438		)	(6,678		)
Comprehensive income (loss)	$	239,151		$	(9,467	)

	Nine months ended
	September 30,
(in thousands)	2011			2010
Net income	$	245,192		$	210,557
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $76.6 million and $55.9 million	125,005			91,141
Reclassification adjustment for derivative instruments, net of tax of ($6.2) million and ($56.9) million	(10,085		)	(92,914		)
Pension and postretirement plans, net of tax of ($4.9) million and ($2.9) million	(9,073		)	(5,420		)
Comprehensive income	$	351,039		$	203,364

Schedule of Accumulated Other Comprehensive Income (Loss)

(in thousands)	September 30, 2011			December 31, 2010
Unrealized gain (loss) on hedges, net of tax of $43.7 million and ($26.8) million	$	71,253		$	(43,667	)
Pension and postretirement plans, net of tax of ($21.4) million and ($16.5) million	(39,803		)	(30,730		)
Accumulated other comprehensive income (loss)	$	31,450		$	(74,397	)

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2011	Nov. 03, 2011
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Entity Registrant Name	ENERGEN CORP
Entity Central Index Key	0000277595
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		72,093,899
Alabama Gas Corporation
Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q3
Entity Registrant Name	ALABAMA GAS CORP
Entity Central Index Key	0000003146
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,972,052

XML

Acquisition and Dispositions of Oil and Gas Properties (Details) (USD $)	3 Months Ended		9 Months Ended		3 Months Ended										1 Months Ended	9 Months Ended		1 Months Ended				1 Months Ended	9 Months Ended	1 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011 Purchase and Sale Agreement October 2011, Permian Basin, First Acquisition MMBoe	Sep. 30, 2011 Purchase and Sale Agreement October 2011, Permian Basin, First Acquisition Oil Reserves	Sep. 30, 2011 Purchase and Sale Agreement October 2011, Permian Basin, First Acquisition Natural Gas Liquids Reserves	Sep. 30, 2011 Purchase and Sale Agreement October 2011, Permian Basin, First Acquisition Natural Gas Reserves	Sep. 30, 2011 Purchase and Sale Agreement October 2011, Permian Basin, Second Acquisition MMBoe	Sep. 30, 2011 Purchase and Sale Agreement October 2011, Permian Basin, Second Acquisition Oil Reserves	Sep. 30, 2011 Purchase and Sale Agreement October 2011, Permian Basin, Second Acquisition Natural Gas Liquids Reserves	Sep. 30, 2011 Purchase and Sale Agreement October 2011, Permian Basin, Second Acquisition Natural Gas Reserves	Jul. 31, 2011 July 2011, Permian Basin	Apr. 30, 2011 April 2011, Permian Basin A	Dec. 31, 2010 Dec 15, 2010, Permian Basin	Sep. 30, 2011 Dec 15, 2010, Permian Basin	Dec. 15, 2010 Dec 15, 2010, Permian Basin MMBoe	Dec. 31, 2010 Dec 15, 2010, Permian Basin Oil Reserves	Dec. 31, 2010 Dec 15, 2010, Permian Basin Natural Gas Liquids Reserves	Dec. 31, 2010 Dec 15, 2010, Permian Basin Natural Gas Reserves	Dec. 09, 2010 Dec 9, 2010, Permian Basin Boe	Sep. 30, 2010 Sep 30, 2010, Permian Basin MMBoe	Sep. 30, 2011 Sep 30, 2010, Permian Basin	Sep. 30, 2010 Sep 30, 2010, Permian Basin Oil Reserves	Sep. 30, 2010 Sep 30, 2010, Permian Basin Natural Gas Liquids Reserves	Sep. 30, 2010 Sep 30, 2010, Permian Basin Natural Gas Reserves
Significant Acquisitions and Disposals [Line Items]
Consideration - Estimated Purchase Price					$ 158,000,000				$ 54,000,000
Consideration - Purchase Price													22,000,000	37,000,000			73,630,000				103,000,000	188,314,000
Gas and Oil Acreage, Undeveloped, Net														11,000
Proved Developed and Undeveloped Reserves, Net					13.8				3.4								7.6				0	18
Percentage of Undeveloped Portion of Proved Reserves					76.00%				77.00%						92.00%							89.00%
Acquired Proved Reserves by Type of Reserve, Percentage						59.00%	25.00%	16.00%		61.00%	24.00%	15.00%						62.00%	24.00%	14.00%				65.00%	22.00%	13.00%
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties																	41,066,000					151,747,000
Unproved leasehold properties																	32,500,000					35,360,000
Accounts receivable																	143,000					1,461,000
Asset retirement obligation																	(79,000)					(142,000)
Accounts payable																						(112,000)
Total identifiable net assets																	73,630,000					188,314,000
Operating revenues	378,568,000	295,804,000	1,195,331,000	1,204,443,000												6,800,000							32,800,000
Operating income	$ 150,412,000	$ 67,320,000	$ 416,628,000	$ 357,811,000												$ 3,200,000							$ 16,200,000

XML

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

9 Months Ended

Sep. 30, 2011

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)	September 30, 2011				December 31, 2010
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	87,181	$	132	$	60,284
Accretion and depreciation for asset retirement obligation	—		9,007		—		8,681
Risk management activities	44,137		13,050		27,906		32,461
RSE adjustment	25		—		25		—
Enhanced stability reserve	—		—		—		3,794
Other	193		6		223		145
Total regulatory assets	$	44,525	$	109,244	$	28,286	$	105,365
Regulatory liabilities:
RSE adjustment	$	5,068	$	—	$	4,147	$	—
Unbilled service margin	5,143		—		34,197		—
Postretirement liabilities	—		—		—		754
Gas supply adjustment	21,060		—		14,990		—
Asset removal costs, net	—		7,834		—		6,913
Refundable negative salvage	20,545		67,237		22,336		90,504
Asset retirement obligation	—		11,697		—		11,439
Other	33		811		33		837
Total regulatory liabilities	$	51,849	$	87,579	$	75,703	$	110,447

XML

Asset Retirement Obligations (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning			$ 97,415
Liabilities incurred			3,761
Liabilities settled			(1,531)
Accretion expense	1,728	1,561	5,066	4,568
Balance of ARO, end	104,711		104,711
Regulatory Liability, Current	51,849		51,849		75,703
Regulatory Liability, Noncurrent	87,579		87,579		110,447
Alabama Gas Corporation | Asset removal costs
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	0		0		0
Regulatory Liability, Noncurrent	7,834		7,834		6,913
Alabama Gas Corporation | Refundable negative salvage
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	20,545		20,545		22,336
Regulatory Liability, Noncurrent	67,237		67,237		90,504
Refundable negative salvage
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liability, Current	20,545		20,545
Regulatory Liability, Noncurrent	67,237		67,237
Alabama Gas Corporation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance of ARO, beginning					11,400
Balance of ARO, end	11,700		11,700		11,400
Regulatory Liability, Current	51,849		51,849		75,703
Regulatory Liability, Noncurrent	$ 87,579		$ 87,579		$ 110,447

XML

Stock Compensation

9 Months Ended

Sep. 30, 2011

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. On April 27, 2011, the Company amended the Stock Incentive Plan to increase the number of shares authorized for issuance by 3,000,000 shares. This increase resulted in 3,794,326 shares being available for future issuances. Options granted under the 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 293,978 non-qualified option shares during the first quarter of 2011 with a grant-date fair value of $19.65.

2004 Stock Appreciation Rights Plan

The Energen 2004 Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 189,984 awards during the first quarter of 2011. These awards had a fair value of $10.27 as of September 30, 2011.

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 2011, Energen Resources awarded 6,314 Petrotech units with a three-year vesting period. These awards had a fair value of $39.70 as of September 30, 2011.

1997 Deferred Compensation Plan

During the three months and nine months ended September 30, 2011, the Company had noncash purchases of approximately $16,000 and $0.4 million, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

During the nine months ended September 30, 2011, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2010	$	97,415
Liabilities incurred	3,761
Liabilities settled	(1,531		)
Accretion expense	5,066
Balance of ARO as of September 30, 2011	$	104,711

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Commitments and Contingencies (Details) - Environmental Matters (Alabama Gas Corporation, USD $) In Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011
Alabama Gas Corporation
Site Contingency [Line Items]
Environmental Remediation Estimated Cost	$ 4.8
Environmental Remediation Expense	0.6	3.6
Accrual for Environmental Loss Contingencies	$ 0.6	$ 0.6

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Comprehensive Income (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Net income	$ 87,599,000	$ 38,304,000	$ 245,192,000	$ 210,557,000
Other Comprehensive Income (Loss), Net of Tax [Abstract]
Current period change in fair value of derivative instruments, net of tax	172,430,000	(7,244,000)	125,005,000	91,141,000
Reclassification adjustment for derivative instruments, net of tax	(10,440,000)	(33,849,000)	(10,085,000)	(92,914,000)
Pension and postretirement plans, net of tax	(10,438,000)	(6,678,000)	(9,073,000)	(5,420,000)
Comprehensive income	239,151,000	(9,467,000)	351,039,000	203,364,000
Other Comprehensive Income (Loss), Tax [Abstract]
Current period change in fair value of derivative instruments, tax	105,700,000	(4,400,000)	76,600,000	55,900,000
Reclassification adjustement for derivative instruments, tax	(6,400,000)	(20,700,000)	(6,200,000)	(56,900,000)
Pension and postretirement plans, tax	(5,600,000)	(3,600,000)	(4,900,000)	(2,900,000)
Accumulated other comprehensive loss, net of tax
Unrealized gain (loss) on hedges, net	71,253,000		71,253,000		(43,667,000)
Pension and postretirement plans	(39,803,000)		(39,803,000)		(30,730,000)
Accumulated other comprehensive loss	31,450,000		31,450,000		(74,397,000)
Unrealized loss on hedges, tax	43,700,000		43,700,000		(26,800,000)
Pension and postretirement plans, tax	$ (21,400,000)		$ (21,400,000)		$ (16,500,000)

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Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2011

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, 2010	$	447
Provision	(24		)
Allowance for credit losses as of September 30, 2011	$	423

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2011

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

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

During the nine months ended September 30, 2011, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

(in thousands)
Balance of ARO as of December 31, 2010	$	97,415
Liabilities incurred	3,761
Liabilities settled	(1,531		)
Accretion expense	5,066
Balance of ARO as of September 30, 2011	$	104,711

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 $11.7 million and $11.4 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of September 30, 2011, and December 31, 2010, respectively. The conditional asset retirement obligations reflect the re-estimation of removal costs associated with Alagasco’s revised depreciation rate. 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 liabilities for accumulated asset removal costs of $7.8 million and $6.9 million for September 30, 2011, and December 31, 2010, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets. As of September 30, 2011, the Company recognized $20.5 million and $67.2 million of refundable negative salvage as regulatory liabilities in current liabilities and deferred credit and other liabilities, respectively, on the balance sheet in response to the June 28, 2010, APSC order.

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Derivative Commodity Instruments

9 Months Ended

Sep. 30, 2011

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. 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 eleven of its active counterparties and in a net loss position with the remaining one at September 30, 2011. The four largest counterparty positions at September 30, 2011, Macquarie Bank Limited, J Aron & Company, Shell Energy North America (US), L.P. and Citibank, N.A. constituted approximately $35.8 million, $29.7 million, $23.5 million and $23.0 million, respectively, of Energen Resources’ net gain on fair value of derivatives. J.P. Morgan Ventures Energy Corporation was the only counterparty in a loss position of $0.2 million.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of September 30, 2011, 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 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 accounting 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)	September 30, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	88,839			$	—		$	88,839
Long-term asset derivative instruments	67,461				—			67,461
Total derivative assets	156,300				—			156,300
Accounts receivable	(25,642		)	*	—			(25,642		)
Accounts payable	(1,298		)		—			(1,298		)
Long-term liability derivative instruments	(9,049		)	*	—			(9,049		)
Total derivative liabilities	(35,989		)		—			(35,989		)
Total derivatives designated	120,311				—			120,311
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	10,745				—			10,745
Long-term asset derivative instruments	42,482				—			42,482
Total derivative assets	53,227				—			53,227
Accounts payable	(40		)		(44,137		)	(44,177		)
Long-term liability derivative instruments	—				(13,050		)	(13,050		)
Total derivative liabilities	(40		)		(57,187		)	(57,227		)
Total derivatives not designated	53,187				(57,187		)	(4,000		)
Total derivatives	$	173,498			$	(57,187	)	$	116,311

(in thousands)	December 31, 2010
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	85,867			$	—		$	85,867
Long-term asset derivative instruments	3,156			*	—			3,156
Total derivative assets	89,023				—			89,023
Accounts receivable	(25,315		)	*	—			(25,315		)
Accounts payable	(50,508		)		—			(50,508		)
Long-term liability derivative instruments	(83,631		)		—			(83,631		)
Total derivative liabilities	(159,454		)		—			(159,454		)
Total derivatives designated	(70,431		)		—			(70,431		)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable	(110		)		(27,906		)	(28,016		)
Long-term liability derivative instruments	—				(32,461		)	(32,461		)
Total derivative liabilities	(110		)		(60,367		)	(60,477		)
Total derivatives not designated	(110		)		(60,367		)	(60,477		)
Total derivatives	$	(70,541	)		$	(60,367	)	$	(130,908	)

* 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 $43.7 million deferred tax liability and a net $26.8 million deferred tax asset included in current and noncurrent deferred income taxes on the consolidated condensed balance sheets related to derivative items included in OCI as of September 30, 2011, and December 31, 2010, respectively.

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

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 September 30, 2011		Three months ended September 30, 2010
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of $105.7 million and ($4.4) million	—	$	172,430	$	(7,244	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	11,207	$	56,456
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	5,631	$	(1,861	)

(in thousands)	Location on Income Statement	Nine months ended September 30, 2011		Nine months ended September 30, 2010
Gain recognized in OCI on derivative (effective portion), net of tax of $76.6 million and $55.9 million	—	$	125,005	$	91,141
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	13,028	$	149,845
Gain recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	3,240	$	18

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 September 30, 2011		Three months ended September 30, 2010
Gain (loss) recognized in income on derivative	Operating revenues	$	53,227	$	—
(in thousands)	Location on Income Statement	Nine months ended September 30, 2011		Nine months ended September 30, 2010
Gain (loss) recognized in income on derivative	Operating revenues	$	53,225	$	(4	)

As of September 30, 2011, $37.4 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 September 30, 2011, the Company had 3 thousand, 1,735 thousand, 3,108 thousand and 2,400 thousand barrels (MBbl) of oil hedges which expire during 2011, 2012, 2013 and 2014 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges. The Company had 1.6 million gallons (MMgal) of natural gas liquid hedges which expire during 2013 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges.

Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	3.5 Bcf	$6.47 Mcf	NYMEX Swaps
	9.7 Bcf	$5.63 Mcf	Basin Specific Swaps
2012	11.0 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
2013	8.8 Bcf	$5.30 Mcf	NYMEX Swaps
	25.1 Bcf	$4.88 Mcf	Basin Specific Swaps
2014	3.0 Bcf	$5.72 Mcf	NYMEX Swaps
	16.8 Bcf	$5.16 Mcf	Basin Specific Swaps
Oil
2011	1,334 MBbl	$83.73 Bbl	NYMEX Swaps
2012	6,282 MBbl	$87.40 Bbl	NYMEX Swaps
2013	6,827 MBbl	$89.31 Bbl	NYMEX Swaps
2014	5,612 MBbl	$90.56 Bbl	NYMEX Swaps
Oil Basis Differential
2011	854 MBbl	*	Basis Swaps
2012	3,124 MBbl	*	Basis Swaps
2013	2,768 MBbl	*	Basis Swaps
Natural Gas Liquids
2011	10.5 MMGal	$0.90 Gal	Liquids Swaps
2012	43.4 MMGal	$0.88 Gal	Liquids Swaps
2013	44.5 MMGal	$1.02 Gal	Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Description
2011	3.9 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

As of September 30, 2011, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2014, and December 31, 2013, respectively.

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). 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.

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 New York Mercantile Exchange (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 liquids swaps.

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

	September 30, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	51,263		$	22,680		$	73,943
Noncurrent assets	84,700			16,475			101,175
Current liabilities	(42,806		)	(2,670		)	(45,476		)
Noncurrent liabilities	(13,050		)	(281		)	(13,331		)
Net derivative asset	$	80,107		$	36,204		$	116,311

	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Current liabilities	(76,527		)	(1,997		)	(78,524		)
Noncurrent liabilities	(107,452		)	(5,484		)	(112,936		)
Net derivative asset (liability)	$	(173,663	)	$	42,755		$	(130,908	)

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

As of September 30, 2011, Alagasco had $44.1 million and $13.1 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities and noncurrent liabilities, respectively. As of December 31, 2010, Alagasco had $27.9 million and $32.5 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 September 30, 2011, and December 31, 2010.

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

	Three months ended			Three months ended
(in thousands)	September 30, 2011			September 30, 2010
Balance at beginning of period	$	13,446		$	91,817
Realized (gains) losses	1,088			(455		)
Unrealized gains relating to instruments held at the reporting date	32,235			26,282
Settlements during period	(10,565		)	(30,767		)
Balance at end of period	$	36,204		$	86,877

	Nine months ended			Nine months ended
(in thousands)	September 30, 2011			September 30, 2010
Balance at beginning of period	$	42,755		$	64,517
Realized (gains) losses	1,088			(455		)
Unrealized gains relating to instruments held at the reporting date	28,681			102,169
Settlements during period	(36,320		)	(79,354		)
Balance at end of period	$	36,204		$	86,877

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Reconciliation of Earnings Per Share (Details) - Earnings Per Share Reconciliation (USD $) In Thousands, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Earnings Per Share Reconciliation
Net Income, Basic EPS	$ 87,599	$ 38,304	$ 245,192	$ 210,557
Basic Shares Oustanding (in shares)	72,068	71,854	72,045	71,838
Earnings Per Share, Basic (dollars per share)	$ 1.22	$ 0.53	$ 3.40	$ 2.93
Effect of dilutive securities
Net Income, Diluted EPS	$ 87,599	$ 38,304	$ 245,192	$ 210,557
Diluted Shares Outstanding (in shares)	72,375	72,070	72,409	72,061
Earnings Per Share, Diluted (dollars per share)	$ 1.21	$ 0.53	$ 3.39	$ 2.92
Stock options
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements	298	199	355	206
Non-vested restricted stock
Effect of dilutive securities
Incremental Common Shares Attributable to Share-based Payment Arrangements	9	17	9	17

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2011

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 $116 million through September 2024. During the nine months ending September 30, 2011 and 2010, Alagasco recognized approximately $36.8 million and $38.1 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 210 million Bcf through August 2020.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has, in certain instances, provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2011, the fixed price purchases under these guarantees had a maximum term outstanding through October 2012 and an aggregate purchase price of $3.7 million with a market value of $3.4 million.

Energen Resources entered into three agreements which commence 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 terminates the agreements prior to the commencement dates, Energen Resources' total resulting exposure is the greater of approximately $2.2 million or all expenses incurred in the preparation of the subject rigs for the operations contemplated by the contract. Upon commencement, Energen Resources' total resulting exposure could be as much as $34 million depending on the contractors ability to remarket the drilling rig.

Income Taxes: Energen and its subsidiaries' 2007 and 2008 federal consolidated income tax returns have been under Internal Revenue Service (IRS) examination. In September 2010, the IRS made certain assessments primarily related to Alagasco’s tax accounting method change for the recovery of its gas distribution property. The Company subsequently filed a petition in United States Tax Court challenging the IRS assessment. During the second quarter of 2011, the Company entered into a settlement agreement with the IRS. Under this settlement, Alagasco was allowed the full repair tax deductions as originally claimed in the 2007 and 2008 federal income tax returns. The Chief Judge of the United States Tax Court signed and entered the Decision putting this settlement agreement into effect on June 16, 2011.

During the current year-to-date, the Company recognized a $2.1 million income tax benefit related to changes in Alabama state income tax laws. In addition, the Company recognized a $1.5 million net benefit for the release of the unrecognized income tax benefit liability due to the Company's settlement with the IRS discussed above. These benefits are partially offset by $2.1 million of income tax expense for additional unrecognized tax benefit liabilities. 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 $2.4 million during the nine months ended September 30, 2011.

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 manufactured gas distribution sites (one of which it still owns). Subject to the following paragraph discussing the Huntsville, Alabama manufactured gas plant site, an investigation of the sites does not indicate the present need for 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 June 2009, Alagasco received a General Notice Letter from the United States Environmental Protection Agency (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, developed an action plan for the site and as of June 30, 2011, had substantially completed the action plan. Based on information available at this time, Alagasco estimates that it will incur costs associated with the site of approximately $4.8 million, including costs previously incurred. During the three months and nine months ended September 30, 2011, the Company incurred costs of $0.6 million and $3.6 million, respectively, associated with the site. As of September 30, 2011, the Company has accrued a contingent liability of $0.6 million in addition to the costs previously incurred. If it is determined that further work is appropriate or required by the EPA, then actual costs will likely exceed the estimate. Alagasco expects to recover such costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account of which the remaining 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 $20 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 Department's findings and the ONRR Order. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2011.

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Recently Issued Accounting Standards

9 Months Ended

Sep. 30, 2011

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

Recently Issued Accounting Standards

RECENTLY ISSUED ACCOUNTING STANDARDS

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. These amendments require that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company is currently evaluating the impact of the ASU.

In May 2011, the FASB issued ASU No. 2011-04, Fair Value Measurement (Topic 820): 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. The Company is currently evaluating the impact of the ASU.

In July 2010, the FASB issued ASU No. 2010-20, Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses. These disclosures, as of the end of a reporting period, are effective for the interim and annual reporting periods ending on or after December 15, 2010. The disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The disclosures required under this standard have been included in Note 10, Financial Instruments.

On January 1, 2010, the Company adopted Accounting Standard Update (ASU) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures About Fair Value Measurements. These disclosures are effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010, and for interim reporting periods within those years. The disclosures required under this standard have been included in Note 3, Derivative Commodity Instruments.

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Financial Instruments

9 Months Ended

Sep. 30, 2011

Fair Value Disclosures [Abstract]

Financial Instruments

FINANCIAL INSTRUMENTS

In August 2011, the Company issued $400 million of Senior Notes with an interest rate of 4.625% percent due September 1, 2021. The long-term debt proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources.

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 $860.3 million and has a carrying value of $805.4 million at September 30, 2011. The fair value of Alagasco's fixed-rate long-term debt, including the current portion, approximates $221.9 million and has a carrying value of $200.4 million at September 30, 2011. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating.

Finance Receivables: Alagasco finances third-party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2011, and December 31, 2010, Alagasco’s finance receivable totaled $10.2 million and $8.8 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 $428,000 as of September 30, 2011.

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, 2010	$	447
Provision	(24		)
Allowance for credit losses as of September 30, 2011	$	423

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Derivative Commodity Instruments (Details) - Fair Value Derivatives (USD $) In Thousands	Sep. 30, 2011		Dec. 31, 2010
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	$ 116,311		$ (130,908)
Oil and Gas Operations
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	173,498		(70,541)
Oil and Gas Operations | Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	156,300		89,023
Derivative Liability, Fair Value, Net	(35,989)		(159,454)
Derivative, Fair Value, Net	120,311		(70,431)
Oil and Gas Operations | Designated as Hedging Instrument | Accounts receivable
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	88,839		85,867
Derivative Liability, Fair Value, Gross Asset	(25,642)	[1]	(25,315)	[1]
Oil and Gas Operations | Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1,298)		(50,508)
Oil and Gas Operations | Designated as Hedging Instrument | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	67,461	[1]	3,156	[1]
Oil and Gas Operations | Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(9,049)		(83,631)
Oil and Gas Operations | Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	53,227
Derivative Liability, Fair Value, Gross Liability	(40)		(110)
Derivative, Fair Value, Net	53,187		(110)
Oil and Gas Operations | Not Designated as Hedging Instrument | Accounts receivable
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,745
Oil and Gas Operations | Not Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(40)		(110)
Oil and Gas Operations | Not Designated as Hedging Instrument | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	42,482	[1]
Oil and Gas Operations | Not Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Natural Gas Distribution
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	(57,187)		(60,367)
Natural Gas Distribution | Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Net	0		0
Derivative, Fair Value, Net	0		0
Natural Gas Distribution | Designated as Hedging Instrument | Accounts receivable
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Derivative Liability, Fair Value, Gross Asset	0		0
Natural Gas Distribution | Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Natural Gas Distribution | Designated as Hedging Instrument | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Natural Gas Distribution | Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Natural Gas Distribution | Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	(57,187)		(60,367)
Derivative, Fair Value, Net	(57,187)		(60,367)
Natural Gas Distribution | Not Designated as Hedging Instrument | Accounts receivable
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Natural Gas Distribution | Not Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(44,137)		(27,906)
Natural Gas Distribution | Not Designated as Hedging Instrument | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Natural Gas Distribution | Not Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(13,050)		(32,461)
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	156,300		89,023
Derivative Liability, Fair Value, Net	(35,989)		(159,454)
Derivative, Fair Value, Net	120,311		(70,431)
Designated as Hedging Instrument | Accounts receivable
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	88,839		85,867
Derivative Liability, Fair Value, Gross Asset	(25,642)		(25,315)
Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1,298)		(50,508)
Designated as Hedging Instrument | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	67,461		3,156
Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(9,049)		(83,631)
Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	53,227
Derivative Liability, Fair Value, Gross Liability	(57,227)		(60,477)
Derivative, Fair Value, Net	(4,000)		(60,477)
Not Designated as Hedging Instrument | Accounts receivable
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,745
Not Designated as Hedging Instrument | Accounts Payable
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(44,177)		(28,016)
Not Designated as Hedging Instrument | Other Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	42,482
Not Designated as Hedging Instrument | Other Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ (13,050)		$ (32,461)

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

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2011

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

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	2,293		$	2,144		$	6,879		$	6,430
Interest cost	2,740			2,841			8,220			8,524
Expected long-term return on assets	(3,868		)	(3,229		)	(11,603		)	(9,686		)
Actuarial loss	1,609			1,443			4,826			4,330
Prior service cost amortization	124			124			372			372
Net periodic expense	$	2,898		$	3,323		$	8,694		$	9,970

The Companyanticipates required contributions of approximately $7.2 million during 2011 to the 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 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 2011. For the three months and nine months ending September 30, 2011, the Company made benefit payments aggregating $36,000 and $2.2 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $36,000 through the remainder of 2011.

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	442		$	516		$	1,327		$	1,548
Interest cost	1,111			1,208			3,332			3,625
Expected long-term return on assets	(1,104		)	(996		)	(3,314		)	(2,990		)
Transition amortization	479			479			1,438			1,438
Net periodic expense	$	928		$	1,207		$	2,783		$	3,621

For the three months and nine months ended September 30, 2011, the Company made contributions aggregating $0.9 million and $2.8 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $0.9 million to postretirement benefit plan assets through the remainder of 2011. During the first quarter of 2010, the Company recognized $128,000 in income tax expense resulting from a reduction in deferred tax asset related to changes in the tax treatment for the Medicare Part D subsidy under the recently enacted health care reform legislation.

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Basis of Presentation

9 Months Ended

Sep. 30, 2011

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, 2010, 2009 and 2008, included in the 2010 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 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 consisted of normal recurring items.

During the first quarter of 2010, Alagasco identified an error in calculating the estimate of the allowance for doubtful accounts as of December 31, 2009. This error resulted in a $3 million overstatement to the allowance for doubtful accounts and a corresponding overstatement of net income by approximately $0.6 million (approximately $0.01 per diluted share) after reflecting the regulatory limits on Alagasco’s allowed rate of return for rate year ending September 30, 2010, in the application of Rate Stabilization and Equalization. The Company considered the net impact of this adjustment on the prior quarterly and year-end results, and the results of Alagasco and Energen for the year ended December 31, 2010, and determined that the amount was not material to these periods. The Company corrected this error in the first quarter of 2010.

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Reconciliation of Earnings Per Share (EPS)

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Reconciliation of Earnings Per Share (EPS)

RECONCILIATION OF EARNINGS PER SHARE (EPS)

	Three months ended					Three months ended
(in thousands, except per share amounts)	September 30, 2011					September 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	87,599	72,068	$	1.22	$	38,304	71,854	$	0.53
Effect of dilutive securities
Stock options			298					199
Non-vested restricted stock			9					17
Diluted EPS	$	87,599	72,375	$	1.21	$	38,304	72,070	$	0.53

	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2011					September 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	245,192	72,045	$	3.40	$	210,557	71,838	$	2.93
Effect of dilutive securities
Stock options			355					206
Non-vested restricted stock			9					17
Diluted EPS	$	245,192	72,409	$	3.39	$	210,557	72,061	$	2.92

For the three months and nine months ended September 30, 2011, the Company had 293,978 options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months and nine months ended September 30, 2010, the Company had 479,820 options that were excluded from the computation of diluted EPS. For the three months and nine months ended September 30, 2011 and 2010, the Company had no shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

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Employee Benefit Plans (Details) (USD $)	3 Months Ended			9 Months Ended		3 Months Ended		9 Months Ended
	Mar. 31, 2010	Sep. 30, 2011 Pension Plans	Sep. 30, 2010 Pension Plans	Sep. 30, 2011 Pension Plans	Sep. 30, 2010 Pension Plans	Sep. 30, 2011 Postretirement Benefit Plans	Sep. 30, 2010 Postretirement Benefit Plans	Sep. 30, 2011 Postretirement Benefit Plans	Sep. 30, 2010 Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost		$ 2,293,000	$ 2,144,000	$ 6,879,000	$ 6,430,000	$ 442,000	$ 516,000	$ 1,327,000	$ 1,548,000
Interest cost		2,740,000	2,841,000	8,220,000	8,524,000	1,111,000	1,208,000	3,332,000	3,625,000
Expected long-term return on assets		(3,868,000)	(3,229,000)	(11,603,000)	(9,686,000)	(1,104,000)	(996,000)	(3,314,000)	(2,990,000)
Actuarial loss		1,609,000	1,443,000	4,826,000	4,330,000
Prior service cost amortization		124,000	124,000	372,000	372,000
Transition amortization						479,000	479,000	1,438,000	1,438,000
Net periodic expense		2,898,000	3,323,000	8,694,000	9,970,000	928,000	1,207,000	2,783,000	3,621,000
Estimated Future Employer Contributions in Current Fiscal Year		7,200,000		7,200,000		900,000		900,000
Benefit Payments Made in Current Fiscal Year		36,000		2,200,000
Estimated Future Benefit Payments in Current Fiscal Year		36,000
Contributions by Employer in Current Fiscal Year						900,000		2,800,000
Income Tax Expense, Tax Treatement for Medicare Part D subsidy	$ 128,000

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Derivative Commodity Instruments (Details) - Derivatives (USD $)	Sep. 30, 2011		Dec. 31, 2010
Derivative [Line Items]
Deferred tax assets (liabilities), net	$ (43,700,000)		$ 26,800,000
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Noncurrent assets	101,175,000		0
Noncurrent liabilities	(13,331,000)		(112,936,000)
Alabama Gas Corporation | Cash Flow Hedges | 2011 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	3.9
Alabama Gas Corporation | Cash Flow Hedges | 2012 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	17.2
Alabama Gas Corporation | Cash Flow Hedges | 2013 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	1.5
Cash Flow Hedges | Macquarie Bank Limited [Member]
Derivative [Line Items]
Derivative, Net Gain Position	35,800,000
Cash Flow Hedges | J Aron and Company [Member]
Derivative [Line Items]
Derivative, Net Gain Position	29,700,000
Cash Flow Hedges | Shell Energy North America US, L.P. [Member]
Derivative [Line Items]
Derivative, Net Gain Position	23,500,000
Cash Flow Hedges | Citibank, N.A. [Member]
Derivative [Line Items]
Derivative, Net Gain Position	23,000,000
Cash Flow Hedges | J.P. Morgan Ventures Energy Corporation [Member]
Derivative [Line Items]
Derivative, Net Loss Position	200,000
Cash Flow Hedges | 2011 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	3.5
Average Contract Price, Per Mcf	6.47
Cash Flow Hedges | 2011 | Natural Gas | Basin Specific Swaps
Derivative [Line Items]
Total hedged Volumes	9.7
Average Contract Price, Per Mcf	5.63
Cash Flow Hedges | 2011 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	1,334
Average Contract Price, Per Gal	83.73
Cash Flow Hedges | 2011 | Crude Oil | Basis Swap
Derivative [Line Items]
Total hedged Volumes	854
Average Contract Price, Per Gal		[1]
Cash Flow Hedges | 2011 | Natural Gas Liquids | Liquids Swaps
Derivative [Line Items]
Total hedged Volumes	10.5
Average Contract Price, Per Bbl	0.90
Cash Flow Hedges | 2012 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	11.0
Average Contract Price, Per Mcf	5.07
Cash Flow Hedges | 2012 | Natural Gas | Basin Specific Swaps
Derivative [Line Items]
Total hedged Volumes	29.5
Average Contract Price, Per Mcf	4.60
Cash Flow Hedges | 2012 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	6,282
Average Contract Price, Per Gal	87.40
Cash Flow Hedges | 2012 | Crude Oil | Basis Swap
Derivative [Line Items]
Total hedged Volumes	3,124
Average Contract Price, Per Gal		[1]
Cash Flow Hedges | 2012 | Natural Gas Liquids | Liquids Swaps
Derivative [Line Items]
Total hedged Volumes	43.4
Average Contract Price, Per Bbl	0.88
Cash Flow Hedges | 2013 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	8.8
Average Contract Price, Per Mcf	5.30
Cash Flow Hedges | 2013 | Natural Gas | Basin Specific Swaps
Derivative [Line Items]
Total hedged Volumes	25.1
Average Contract Price, Per Mcf	4.88
Cash Flow Hedges | 2013 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	6,827
Average Contract Price, Per Gal	89.31
Cash Flow Hedges | 2013 | Crude Oil | Basis Swap
Derivative [Line Items]
Total hedged Volumes	2,768
Average Contract Price, Per Gal		[1]
Cash Flow Hedges | 2013 | Natural Gas Liquids | Liquids Swaps
Derivative [Line Items]
Total hedged Volumes	44.5
Average Contract Price, Per Bbl	1.02
Cash Flow Hedges | 2014 | Natural Gas | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	3.0
Average Contract Price, Per Mcf	5.72
Cash Flow Hedges | 2014 | Natural Gas | Basin Specific Swaps
Derivative [Line Items]
Total hedged Volumes	16.8
Average Contract Price, Per Mcf	5.16
Cash Flow Hedges | 2014 | Crude Oil | NYMEX Swaps
Derivative [Line Items]
Total hedged Volumes	5,612
Average Contract Price, Per Gal	90.56
Fair Value Hedging | Expires during 2011 | Crude Oil
Derivative [Line Items]
Total hedged Volumes	3
Fair Value Hedging | Expires during 2012 | Crude Oil
Derivative [Line Items]
Total hedged Volumes	1,735
Fair Value Hedging | Expires during 2013 | Natural Gas
Derivative [Line Items]
Total hedged Volumes	0
Fair Value Hedging | Expires during 2013 | Crude Oil
Derivative [Line Items]
Total hedged Volumes	3,108
Fair Value Hedging | Expires during 2014 | Crude Oil
Derivative [Line Items]
Total hedged Volumes	2,400
Alabama Gas Corporation
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Noncurrent liabilities	(13,050,000)		(32,461,000)
Alabama Gas Corporation | Level 2 | Fair Value, Measurements, Recurring
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Current liabilities	(44,100,000)		(27,900,000)
Noncurrent liabilities	(13,100,000)		(32,500,000)
Level 2 | Fair Value, Measurements, Recurring
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Current assets	51,263,000	[2]	10,316,000	[2]
Noncurrent assets	84,700,000	[2]
Current liabilities	(42,806,000)	[2]	(76,527,000)	[2]
Noncurrent liabilities	(13,050,000)	[2]	(107,452,000)	[2]
Net derivative asset (liability)	80,107,000	[2]	(173,663,000)	[2]
Level 3 | Fair Value, Measurements, Recurring
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Current assets	22,680,000	[2]	50,236,000	[2]
Noncurrent assets	16,475,000	[2]
Current liabilities	(2,670,000)	[2]	(1,997,000)	[2]
Noncurrent liabilities	(281,000)	[2]	(5,484,000)	[2]
Net derivative asset (liability)	36,204,000	[2]	42,755,000	[2]
Fair Value, Measurements, Recurring
Derivative Assets and Liabilities, Measured at Fair Value, on Recurring Basis
Current assets	73,943,000		60,552,000
Noncurrent assets	101,175,000
Current liabilities	(45,476,000)		(78,524,000)
Noncurrent liabilities	(13,331,000)		(112,936,000)
Net derivative asset (liability)	$ 116,311,000		$ (130,908,000)

[1] Average contract prices are not meaningful due to the varying nature of each contract.

[2] 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

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Segment Information

SEGMENT INFORMATION

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

	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Operating revenues
Oil and gas operations	$	318,952		$	234,111		$	779,834		$	706,311
Natural gas distribution	59,616			61,693			415,497			498,132
Total	$	378,568		$	295,804		$	1,195,331		$	1,204,443
Operating income (loss)
Oil and gas operations	$	161,331		$	76,644		$	351,808		$	289,385
Natural gas distribution	(10,681		)	(9,015		)	65,541			69,378
Eliminations and corporate expenses	(238		)	(309		)	(721		)	(952		)
Total	$	150,412		$	67,320		$	416,628		$	357,811
Other income (expense)
Oil and gas operations	$	(9,363	)	$	(4,848	)	$	(20,632	)	$	(17,274	)
Natural gas distribution	(4,162		)	(2,119		)	(10,115		)	(8,882		)
Eliminations and other	94			(463		)	182			(1,225		)
Total	$	(13,431	)	$	(7,430	)	$	(30,565	)	$	(27,381	)
Income before income taxes	$	136,981		$	59,890		$	386,063		$	330,430

(in thousands)	September 30, 2011		December 31, 2010
Identifiable assets
Oil and gas operations	$	3,752,437	$	3,160,601
Natural gas distribution	1,107,188		1,166,899
Eliminations and other	15,817		36,060
Total	$	4,875,442	$	4,363,560

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Commitments and Contingencies (Details) - Income Taxes (USD $) In Millions	9 Months Ended
	Sep. 30, 2011
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits, Increases Resulting from Settlements with Taxing Authorities	$ 1.5
Unrecognized Tax Benefits, Period Increase (Decrease)	2.1
State and Local Jurisdiction
Income Tax Contingency [Line Items]
Income Tax Reconciliation, Change in Enacted Tax Rate	$ (2.1)

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Acquisition and Dispositions of Oil and Gas Properties (Tables)

9 Months Ended

Sep. 30, 2011

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 September 30, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	188,314
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,747
Unproved leasehold properties	35,360
Accounts receivable	1,461
Asset retirement obligation	(142		)
Accounts payable	(112		)
Total identifiable net assets	$	188,314

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of December 15, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,066
Unproved leasehold properties	32,500
Accounts receivable	143
Asset retirement obligation	(79		)
Total identifiable net assets	$	73,630

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Derivative Commodity Instruments (Details) - Derivative Instruments by Income Statement Location (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Gain recognized in OCI on derivative (effective portion), net of tax	$ 172,430,000	$ (7,244,000)	$ 125,005,000	$ 91,141,000
Gain (loss) recognized in OCI on derivative (effective portion), Tax	105,700,000	(4,400,000)	76,600,000	55,900,000
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimated Net Amount to be Transferred	37,400,000
Operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss) reclassified from accumulated OCI into income (effective portion)	11,207,000	56,456,000	13,028,000	149,845,000
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	5,631,000	(1,861,000)	3,240,000	18,000
Gain (loss) recongnized in income on derivative	$ 53,227,000	$ 0	$ 53,225,000	$ (4,000)

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Commitments and Contingencies (Details) - Commitments and Agreements (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2011	Sep. 30, 2010
Long-term Purchase Commitment [Line Items]
Recorded Unconditional Purchase Obligation, Time Period	October 2012
Drilling Plans, Agreement to Secure Drilling Rigs, Number of Agreements		3
Alabama Gas Corporation | Natural Gas
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Time Period	August 2020
Long-term Purchase Commitment, Minimum Quantity Required	210,454,800
Recorded Unconditional Purchase Obligation	$ 3,700,000	$ 3,700,000
Recorded Unconditional Purchase Obligation, Market Value	3,400,000	3,400,000
Alabama Gas Corporation | Natural Gas, Delivery and Storage
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Amount	116,000,000
Long-term Purchase Commitment, Time Period	September 2024
Long Term Commitments Expense Recognized in Statements of Operations		36,800,000	38,100,000
Agreement Termination
Long-term Purchase Commitment [Line Items]
Loss Contingency, Range of Possible Loss, Minimum	2,200,000	2,200,000
Loss Contingency, Range of Possible Loss, Maximum	34,000,000	34,000,000
Pending or threatened legal proceedings
Long-term Purchase Commitment [Line Items]
Loss Contingency Accrual, Carrying Value, Period Increase (Decrease)		$ 2,400,000

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Regulatory Matters (Details) (USD $)	1 Months Ended		3 Months Ended	9 Months Ended		12 Months Ended
	Dec. 31, 2010	Dec. 31, 2009	Sep. 30, 2011	Sep. 30, 2011	Sep. 30, 2010	Jun. 30, 2011	Sep. 30, 2010	Dec. 31, 1998
Regulatory Matters [Line Items]
Regulatory Assets, Noncurrent	$ 105,365,000		$ 109,244,000	$ 109,244,000
Alabama Gas Corporation | Enhanced stability reserve
Regulatory Matters [Line Items]
Regulatory Assets, Noncurrent	3,794,000		0	0
Alabama Gas Corporation
Regulatory Matters [Line Items]
Enahanced Stability Reserve Extension Period				7 years
Revenue Impact of Rate Adjustments	(1,300,000)	10,200,000	(1,200,000)	(6,700,000)	(10,600,000)
Adjustment Requirement Threshold for Return on Equity as Percentage of Operations and Maintenance Expenses to Consumer Price Index				0.75
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.
Extraordinary Bad Debt Expense, Excluded from CCM Calculation							2,500,000
Negative Revenue Variance, Large Commercial and Industrial Customer Budget, Minimum Amount, Charged to Enhanced Stability Reserve								250,000
Accretion to Enhanced Stability Reserve, Monthly								40,000
Amortization Expense, Enhanced Stability Reserve, Annual Amount				660,000
Enahanced Stability Reserve Amortization Period						5 years
Enhanced Stability Reserve Refund Period						9 years
Regulatory Assets, Noncurrent	105,365,000		109,244,000	109,244,000
Alabama Gas Corporation | 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
Accretion to Enhanced Stability Reserve, Monthly				55,000
Alabama Gas Corporation | 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
Alabama Gas Corporation | 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
Alabama Gas Corporation | 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
Alabama Gas Corporation | Force Majeure Event Costs
Regulatory Matters [Line Items]
Extraordinary Operating and Maintenance Expenses, Minimum Amount, Charged to Enhanced Stability Reserve								200,000
Alabama Gas Corporation | Minimum
Regulatory Matters [Line Items]
Allowed Return on Average Common Equity				13.15%
Alabama Gas Corporation | 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%
Enhanced Stability Reserve								$ 4,000,000

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Acquisition and Dispositions of Oil and Gas Properties

9 Months Ended

Sep. 30, 2011

Acquisition and Dispositions of Oil and Gas Properties Abstract

Acquisition and Dispositions of Oil and Gas Properties

ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

In October 2011, Energen signed a purchase and sale agreement to buy interests in certain liquids-rich properties in the Permian Basin for a cash purchase price of $158 million (subject to closing adjustments). This sale is expected to close during the fourth quarter and will have an effective date of August 1, 2011. Energen will acquire total proved reserves of approximately 13.8 million barrels of oil equivalents (MMBOE). Of the proved reserves acquired, an estimated 76 percent are undeveloped. Approximately 59 percent of the acquisition proved reserves are oil, 25 percent are natural gas liquids and natural gas comprises the remaining 16 percent. Energen Resources will use its credit facilities and internally generated cash flows to finance the acquisition.

Energen signed a purchase and sale agreement in October 2011 to buy interests in certain properties in the Permian Basin for a cash purchase price of $54 million (subject to closing adjustments). This sale is expected to close during the fourth quarter and will have an effective date of July 1, 2011. Energen will acquire total proved reserves of approximately 3.4 MMBOE. Of the proved reserves acquired, an estimated 77 percent are undeveloped. Approximately 61 percent of the acquisition proved reserves are oil, 24 percent are natural gas liquids and natural gas comprises the remaining 15 percent. Energen Resources will use its credit facilities and internally generated cash flows to finance the acquisition.

In July 2011, Energen completed the purchase of liquids-rich properties in the Permian Basin for a cash purchase price of approximately $22 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.

On December 15, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash purchase price of $74 million. This purchase had an effective date of December 1, 2010. Energen acquired proved reserves of approximately 7.6 MMBOE. Of the proved reserves acquired, an estimated 92 percent are undeveloped. Approximately 62 percent of the acquisition’s estimated proved reserves are oil, 24 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 December 15, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	73,630
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	41,066
Unproved leasehold properties	32,500
Accounts receivable	143
Asset retirement obligation	(79		)
Total identifiable net assets	$	73,630

Included in the Company’s consolidated results of operations for the nine months ended September 30, 2011, are $6.8 million of operating revenues and $3.2 million in operating income resulting from the operation of the properties acquired above.

On December 9, 2010, Energen completed the asset purchase of certain liquids-rich properties in the Permian Basin from SandRidge Energy, Inc. for a cash purchase price of $103 million (subject to closing adjustments). This purchase had an effective date of December 9, 2010. Energen acquired no proved reserves related to this acquisition. Energen Resources used its credit facilities and internally generated cash flows to finance the acquisition.

On September 30, 2010, Energen completed the purchase of certain properties in the Permian Basin for a cash price of $188 million. This purchase had an effective date of September 1, 2010. Energen acquired proved reserves of approximately 18 MMBOE. Of the proved reserves acquired, an estimated 89 percent are undeveloped. Approximately 65 percent of the proved reserves are oil, 22 percent are natural gas liquids and natural gas comprises the remaining 13 percent. Energen Resources used its 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 September 30, 2010, (including the effects of closing adjustments).

(in thousands)
Consideration given
Cash (net)	$	188,314
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	151,747
Unproved leasehold properties	35,360
Accounts receivable	1,461
Asset retirement obligation	(142		)
Accounts payable	(112		)
Total identifiable net assets	$	188,314

Included in the Company’s consolidated results of operations for the nine months ended September 30, 2011, are $32.8 million of operating revenues and $16.2 million in operating income resulting from the operation of the properties acquired above.

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Comprehensive Income (Loss)

9 Months Ended

Sep. 30, 2011

Statement of Income and Comprehensive Income [Abstract]

Comprehensive Income (Loss)

COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended
	September 30,
(in thousands)	2011			2010
Net income	$	87,599		$	38,304
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $105.7 million and ($4.4) million	172,430			(7,244		)
Reclassification adjustment for derivative instruments, net of tax of ($6.4) million and ($20.7) million	(10,440		)	(33,849		)
Pension and postretirement plans, net of tax of ($5.6) million and ($3.6) million	(10,438		)	(6,678		)
Comprehensive income (loss)	$	239,151		$	(9,467	)

	Nine months ended
	September 30,
(in thousands)	2011			2010
Net income	$	245,192		$	210,557
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $76.6 million and $55.9 million	125,005			91,141
Reclassification adjustment for derivative instruments, net of tax of ($6.2) million and ($56.9) million	(10,085		)	(92,914		)
Pension and postretirement plans, net of tax of ($4.9) million and ($2.9) million	(9,073		)	(5,420		)
Comprehensive income	$	351,039		$	203,364

(in thousands)	September 30, 2011			December 31, 2010
Unrealized gain (loss) on hedges, net of tax of $43.7 million and ($26.8) million	$	71,253		$	(43,667	)
Pension and postretirement plans, net of tax of ($21.4) million and ($16.5) million	(39,803		)	(30,730		)
Accumulated other comprehensive income (loss)	$	31,450		$	(74,397	)

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Reconciliation of Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2011

Earnings Per Share [Abstract]

Schedule of Earnings Per Share Reconciliation

	Three months ended					Three months ended
(in thousands, except per share amounts)	September 30, 2011					September 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	87,599	72,068	$	1.22	$	38,304	71,854	$	0.53
Effect of dilutive securities
Stock options			298					199
Non-vested restricted stock			9					17
Diluted EPS	$	87,599	72,375	$	1.21	$	38,304	72,070	$	0.53

	Nine months ended					Nine months ended
(in thousands, except per share amounts)	September 30, 2011					September 30, 2010
	Net			Per Share		Net			Per Share
	Income		Shares	Amount		Income		Shares	Amount
Basic EPS	$	245,192	72,045	$	3.40	$	210,557	71,838	$	2.93
Effect of dilutive securities
Stock options			355					206
Non-vested restricted stock			9					17
Diluted EPS	$	245,192	72,409	$	3.39	$	210,557	72,061	$	2.92

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Stock Compensation (Details) (USD $)	9 Months Ended	3 Months Ended		3 Months Ended		9 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2011	Mar. 31, 2011 Stock Incentive Plan	Apr. 27, 2011 Stock Incentive Plan	Sep. 30, 2011 Stock Appreciation Rights Plan	Mar. 31, 2011 Stock Appreciation Rights Plan	Sep. 30, 2011 Stock Appreciation Rights Plan	Sep. 30, 2011 Petrotech Incentive Plan	Sep. 30, 2011 Petrotech Incentive Plan	Sep. 30, 2011 Deferred Compensation Plan	Sep. 30, 2011 Deferred Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award
Number of Shares Authorized			3,000,000
Number of Shares Available for Grant			3,794,326
Expiration Period	10 years
Vesting Period	3 years					3 years		3 years
Grants in Period, Options		293,978
Grants in Period, Options, Fair Value		$ 19.65
Grants in Period, Other than Options					189,984			6,314
Grants in Period, Other than Options, Fair Value				$ 10.27			$ 39.70
Noncash Payments for Repurchase of Common Stock									$ 16,000	$ 400,000

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Basis of Presentation (Details) (Alabama Gas Corporation, USD $) In Millions, except Per Share data	3 Months Ended
	Mar. 31, 2010
Overstatement to allowance for doubtful accounts
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount	$ 3.0
Overstatement of net income
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount	$ 0.6
Earnings Per Share, Diluted
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Per Share	$ 0.01

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Consolidated Condensed Statements of Cash Flows (USD $) In Thousands	9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010
Operating Activities
Net income	$ 245,192	$ 210,557
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	199,559	185,025
Accretion expense	5,066	4,568
Deferred income taxes	120,656	95,005
Bad debt expense	3,197	2,969
Exploratory expense	10,773	53,642
Change in derivative fair value	(59,581)	278
Gain on sale of assets	(5,991)	(529)
Other, net	5,913	(4,849)
Net change in:
Accounts receivable	48,585	51,577
Inventories	(15,493)	(8,498)
Accounts payable	(26,877)	(15,449)
Amounts due customers including gas supply pass-through	7,342	22,076
Income tax receivable	39,347	(48,284)
Pension and other postretirement benefit contributions	(5,025)	(40,988)
Other current assets and liabilities	21,286	10,839
Net cash provided by operating activities	593,949	517,939
Investing Activities
Additions to property, plant and equipment	(634,427)	(309,849)
Acquisitions, net of cash acquired	(106,578)	(208,667)
Proceeds from sale of assets	7,401	607
Purchase of short-term investments	0	(154,880)
Sale of short-term investments	0	79,938
Other, net	(946)	(1,395)
Net cash used in investing activities	(734,550)	(594,246)
Financing Activities
Payment of dividends on common stock	(29,188)	(28,030)
Issuance of common stock	6,221	594
Issuance of long-term debt	399,952	0
Payment of long-term debt	(5,407)	(707)
Net change in short-term debt	(230,000)	42,000
Tax benefit on stock compensation	922	720
Debt issuance costs	(3,162)	0
Net cash provided by financing activities	139,338	14,577
Net change in cash and cash equivalents	(1,263)	(61,730)
Cash and cash equivalents at beginning of period	22,659	75,844
Cash and Cash Equivalents at End of Period	21,396	14,114
Alabama Gas Corporation
Operating Activities
Net income	35,344	36,786
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	29,606	34,380
Deferred income taxes	16,626	21,889
Bad debt expense	3,184	2,979
Other, net	227	(16,188)
Net change in:
Accounts receivable	41,085	40,921
Inventories	(6,173)	(4,782)
Accounts payable	(22,155)	(16,381)
Amounts due customers including gas supply pass-through	7,342	22,076
Income tax receivable	6,807	(7,990)
Pension and other postretirement benefit contributions	(2,108)	(25,185)
Other current assets and liabilities	(8,474)	8,917
Net cash provided by operating activities	101,311	97,422
Investing Activities
Additions to property, plant and equipment	(57,424)	(74,710)
Other, net	177	(3,807)
Net cash used in investing activities	(57,247)	(78,517)
Financing Activities
Payment of dividends on common stock	(29,183)	(37,367)
Payment of long-term debt	(5,407)	(707)
Net decreases in advances from affiliates	370	(24,962)
Net change in short-term debt	(20,000)	42,000
Net cash provided by financing activities	(54,220)	(21,036)
Net change in cash and cash equivalents	(10,156)	(2,131)
Cash and cash equivalents at beginning of period	16,910	9,460
Cash and Cash Equivalents at End of Period	$ 6,754	$ 7,329

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2011

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

	Three months ended						Nine months ended
	September 30,						September 30,
(in thousands)	2011			2010			2011			2010
Operating revenues
Oil and gas operations	$	318,952		$	234,111		$	779,834		$	706,311
Natural gas distribution	59,616			61,693			415,497			498,132
Total	$	378,568		$	295,804		$	1,195,331		$	1,204,443
Operating income (loss)
Oil and gas operations	$	161,331		$	76,644		$	351,808		$	289,385
Natural gas distribution	(10,681		)	(9,015		)	65,541			69,378
Eliminations and corporate expenses	(238		)	(309		)	(721		)	(952		)
Total	$	150,412		$	67,320		$	416,628		$	357,811
Other income (expense)
Oil and gas operations	$	(9,363	)	$	(4,848	)	$	(20,632	)	$	(17,274	)
Natural gas distribution	(4,162		)	(2,119		)	(10,115		)	(8,882		)
Eliminations and other	94			(463		)	182			(1,225		)
Total	$	(13,431	)	$	(7,430	)	$	(30,565	)	$	(27,381	)
Income before income taxes	$	136,981		$	59,890		$	386,063		$	330,430

(in thousands)	September 30, 2011		December 31, 2010
Identifiable assets
Oil and gas operations	$	3,752,437	$	3,160,601
Natural gas distribution	1,107,188		1,166,899
Eliminations and other	15,817		36,060
Total	$	4,875,442	$	4,363,560

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Commitments and Contingencies (Details) - New Mexico Audits (Unfavorable Regulatory Action, USD $)	3 Months Ended
	Sep. 30, 2011
Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss, Minimum	$ 142,000
Loss Contingency, Range of Possible Loss, Maximum	$ 20,000,000
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 Department's findings and the ONRR Order. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this Order, and no amount has been accrued as of September 30, 2011.

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2011

Pension Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	2,293		$	2,144		$	6,879		$	6,430
Interest cost	2,740			2,841			8,220			8,524
Expected long-term return on assets	(3,868		)	(3,229		)	(11,603		)	(9,686		)
Actuarial loss	1,609			1,443			4,826			4,330
Prior service cost amortization	124			124			372			372
Net periodic expense	$	2,898		$	3,323		$	8,694		$	9,970

Postretirement Benefit Plans

Defined Benefit Plan Disclosure

Schedule of Net Benefit Costs

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2011			2010			2011			2010
Components of net periodic benefit cost:
Service cost	$	442		$	516		$	1,327		$	1,548
Interest cost	1,111			1,208			3,332			3,625
Expected long-term return on assets	(1,104		)	(996		)	(3,314		)	(2,990		)
Transition amortization	479			479			1,438			1,438
Net periodic expense	$	928		$	1,207		$	2,783		$	3,621

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Regulatory Matters

9 Months Ended

Sep. 30, 2011

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 ended 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 remains 13.15 percent to 13.65 percent throughout the term of the RSE order. Under RSE, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and year-to-date performance, whether Alagasco's return on average common equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and nine months ended September 30, 2011, Alagasco had a net $1.2 million pre-tax and a net $6.7 million pre-tax, respectively, reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. During the nine months ended September 30, 2010, Alagasco had a net $10.6 million pre-tax reduction in revenues to bring the return on average common equity to midpoint within the allowed range of return. Under the provisions of RSE, a $1.3 million annual decrease and a $10.2 million annual increase in revenues became effective December 1, 2010 and 2009, 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. In the rate year ended September 30, 2010, $2.5 million of extraordinary bad debt expense was excluded from the CCM calculation. Alagasco’s O&M expense fell within the Index Range for the rate years ended September 30, 2011 and 2010.

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.

In 1998, the APSC approved an Enhanced Stability Reserve, with a maximum funding level of $4 million, to which Alagasco could charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) negative individual large commercial and industrial customer budget revenue variances that exceed $250,000 during the rate year, if such losses caused Alagasco's year-end return on average common equity (RCE) to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent. Prior to June 28, 2010, the APSC provided for accretions to the ESR of no more than $40,000 monthly until the maximum funding level was achieved, following a year in which a charge against the ESR was made. The APSC’s June 28, 2010, order approved Alagasco’s lower depreciation rates and approved standing authority for Alagasco to charge items to the ESR in excess of its funded balance and to allocate each year from the refundable negative salvage costs that are being refunded to customers over the nine year period the amount necessary to clear the debit balance in the ESR each September 30, subject to APSC-approved guidelines. The APSC also approved the amortization of the ESR into rates over a five year period in cases where the ESR is unfunded or underfunded, subject to APSC-approved guidelines. As a result of these changes in the funding mechanism for the ESR, the APSC suspended the $40,000 per month accruals to the ESR during the nine year period when the refundable negative salvage costs are being refunded to customers.

Following a vote on September 7, 2010, the APSC, by order dated November 1, 2010, approved expansion of the ESR to include extraordinary O&M charges related to environmental response costs and to self insurance costs that exceed $1 million per occurrence. In addition, the APSC raised the thresholds on items that may be charged to the ESR as follows: (1) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a single event that results in more than $275,000 of increased O&M; (2) extraordinary O&M expenses, other than environmental response costs and self insurance costs, resulting from a combination of extraordinary O&M events that result in more than $412,500 of increased O&M; and (3) negative individual large commercial and industrial customer budget variances that exceed $350,000. Charges to the ESR relating to extraordinary O&M expenses can only be made when the Company’s year-end return on average common equity for RSE, not including the ESR charge, is below the midpoint of the APSC-approved return on equity range and only to the extent necessary to bring the RCE to the midpoint of the range. Charges to the ESR relating to negative individual large commercial and industrial customer revenue variances can only be made if such losses cause the RCE to fall below the bottom of the APSC-approved return on equity range currently at 13.15 percent, and then only to the extent necessary to bring the RCE up to the midpoint of the range. In the event that Alagasco’s RCE at September 30 of the related year is above the midpoint, any debit balance in the ESR shall remain in the ESR for recovery in subsequent years subject to the established guidelines. Additionally, the APSC, while confirming the five year amortization period established in the June 28, 2010, order for charges to the ESR in cases where the ESR is unfunded or underfunded, limited the amortization expense to $660,000 annually, with any excess amortization expense over $660,000 in any rate year being carried over and amortized in future rate years until full amortization of the ESR debit balance is complete. The APSC also raised the $40,000 per month accruals to $55,000 per month, but suspended the accruals pending further order of the APSC. Finally, the APSC established guidelines for the documentation, reporting and approval of rate recovery of items charged to the ESR.

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Regulatory Assets and Liabilities

9 Months Ended

Sep. 30, 2011

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	September 30, 2011				December 31, 2010
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	170	$	87,181	$	132	$	60,284
Accretion and depreciation for asset retirement obligation	—		9,007		—		8,681
Risk management activities	44,137		13,050		27,906		32,461
RSE adjustment	25		—		25		—
Enhanced stability reserve	—		—		—		3,794
Other	193		6		223		145
Total regulatory assets	$	44,525	$	109,244	$	28,286	$	105,365
Regulatory liabilities:
RSE adjustment	$	5,068	$	—	$	4,147	$	—
Unbilled service margin	5,143		—		34,197		—
Postretirement liabilities	—		—		—		754
Gas supply adjustment	21,060		—		14,990		—
Asset removal costs, net	—		7,834		—		6,913
Refundable negative salvage	20,545		67,237		22,336		90,504
Asset retirement obligation	—		11,697		—		11,439
Other	33		811		33		837
Total regulatory liabilities	$	51,849	$	87,579	$	75,703	$	110,447

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Derivative Commodity Instruments (Details) - Derivative Instruments Change in Fair Value (Derivative Commodity Instruments, USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Derivative Commodity Instruments
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	$ 13,446	$ 91,817	$ 42,755	$ 64,517
Realized (gains) losses	1,088	(455)	1,088	(455)
Unrealized gains relating to instruments held at the reporting date	32,235	26,282	28,681	102,169
Settlements during period	(10,565)	(30,767)	(36,320)	(79,354)
Balance at end of period	$ 36,204	$ 86,877	$ 36,204	$ 86,877

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Derivative Commodity Instruments (Tables)

9 Months Ended

Sep. 30, 2011

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)	September 30, 2011
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	88,839			$	—		$	88,839
Long-term asset derivative instruments	67,461				—			67,461
Total derivative assets	156,300				—			156,300
Accounts receivable	(25,642		)	*	—			(25,642		)
Accounts payable	(1,298		)		—			(1,298		)
Long-term liability derivative instruments	(9,049		)	*	—			(9,049		)
Total derivative liabilities	(35,989		)		—			(35,989		)
Total derivatives designated	120,311				—			120,311
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable	10,745				—			10,745
Long-term asset derivative instruments	42,482				—			42,482
Total derivative assets	53,227				—			53,227
Accounts payable	(40		)		(44,137		)	(44,177		)
Long-term liability derivative instruments	—				(13,050		)	(13,050		)
Total derivative liabilities	(40		)		(57,187		)	(57,227		)
Total derivatives not designated	53,187				(57,187		)	(4,000		)
Total derivatives	$	173,498			$	(57,187	)	$	116,311

(in thousands)	December 31, 2010
	Oil and Gas Operations				Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	85,867			$	—		$	85,867
Long-term asset derivative instruments	3,156			*	—			3,156
Total derivative assets	89,023				—			89,023
Accounts receivable	(25,315		)	*	—			(25,315		)
Accounts payable	(50,508		)		—			(50,508		)
Long-term liability derivative instruments	(83,631		)		—			(83,631		)
Total derivative liabilities	(159,454		)		—			(159,454		)
Total derivatives designated	(70,431		)		—			(70,431		)
Derivative assets or (liabilities) not designated as hedging instruments
Accounts payable	(110		)		(27,906		)	(28,016		)
Long-term liability derivative instruments	—				(32,461		)	(32,461		)
Total derivative liabilities	(110		)		(60,367		)	(60,477		)
Total derivatives not designated	(110		)		(60,367		)	(60,477		)
Total derivatives	$	(70,541	)		$	(60,367	)	$	(130,908	)

* 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 September 30, 2011		Three months ended September 30, 2010
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of $105.7 million and ($4.4) million	—	$	172,430	$	(7,244	)
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	11,207	$	56,456
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	5,631	$	(1,861	)

(in thousands)	Location on Income Statement	Nine months ended September 30, 2011		Nine months ended September 30, 2010
Gain recognized in OCI on derivative (effective portion), net of tax of $76.6 million and $55.9 million	—	$	125,005	$	91,141
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	13,028	$	149,845
Gain recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	3,240	$	18

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 September 30, 2011		Three months ended September 30, 2010
Gain (loss) recognized in income on derivative	Operating revenues	$	53,227	$	—
(in thousands)	Location on Income Statement	Nine months ended September 30, 2011		Nine months ended September 30, 2010
Gain (loss) recognized in income on derivative	Operating revenues	$	53,225	$	(4	)

Schedule of Hedging Transactions

Energen Resources entered into the following transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2011	3.5 Bcf	$6.47 Mcf	NYMEX Swaps
	9.7 Bcf	$5.63 Mcf	Basin Specific Swaps
2012	11.0 Bcf	$5.07 Mcf	NYMEX Swaps
	29.5 Bcf	$4.60 Mcf	Basin Specific Swaps
2013	8.8 Bcf	$5.30 Mcf	NYMEX Swaps
	25.1 Bcf	$4.88 Mcf	Basin Specific Swaps
2014	3.0 Bcf	$5.72 Mcf	NYMEX Swaps
	16.8 Bcf	$5.16 Mcf	Basin Specific Swaps
Oil
2011	1,334 MBbl	$83.73 Bbl	NYMEX Swaps
2012	6,282 MBbl	$87.40 Bbl	NYMEX Swaps
2013	6,827 MBbl	$89.31 Bbl	NYMEX Swaps
2014	5,612 MBbl	$90.56 Bbl	NYMEX Swaps
Oil Basis Differential
2011	854 MBbl	*	Basis Swaps
2012	3,124 MBbl	*	Basis Swaps
2013	2,768 MBbl	*	Basis Swaps
Natural Gas Liquids
2011	10.5 MMGal	$0.90 Gal	Liquids Swaps
2012	43.4 MMGal	$0.88 Gal	Liquids Swaps
2013	44.5 MMGal	$1.02 Gal	Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

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

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

	September 30, 2011
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	51,263		$	22,680		$	73,943
Noncurrent assets	84,700			16,475			101,175
Current liabilities	(42,806		)	(2,670		)	(45,476		)
Noncurrent liabilities	(13,050		)	(281		)	(13,331		)
Net derivative asset	$	80,107		$	36,204		$	116,311

	December 31, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	10,316		$	50,236		$	60,552
Current liabilities	(76,527		)	(1,997		)	(78,524		)
Noncurrent liabilities	(107,452		)	(5,484		)	(112,936		)
Net derivative asset (liability)	$	(173,663	)	$	42,755		$	(130,908	)

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

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

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

	Three months ended			Three months ended
(in thousands)	September 30, 2011			September 30, 2010
Balance at beginning of period	$	13,446		$	91,817
Realized (gains) losses	1,088			(455		)
Unrealized gains relating to instruments held at the reporting date	32,235			26,282
Settlements during period	(10,565		)	(30,767		)
Balance at end of period	$	36,204		$	86,877

	Nine months ended			Nine months ended
(in thousands)	September 30, 2011			September 30, 2010
Balance at beginning of period	$	42,755		$	64,517
Realized (gains) losses	1,088			(455		)
Unrealized gains relating to instruments held at the reporting date	28,681			102,169
Settlements during period	(36,320		)	(79,354		)
Balance at end of period	$	36,204		$	86,877

Alabama Gas Corporation

Derivative [Line Items]

Schedule of Hedging Transactions

Alagasco entered into the following natural gas transactions for the remainder of 2011 and subsequent years:

Production Period	Total Hedged Volumes	Description
2011	3.9 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

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Consolidated Condensed Statements of Income (USD $) In Thousands, except Per Share data	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
Operating Revenues
Oil and gas operations	$ 318,952	$ 234,111	$ 779,834	$ 706,311
Natural gas distribution	59,616	61,693	415,497	498,132
Total operating revenues	378,568	295,804	1,195,331	1,204,443
Operating Expenses
Cost of gas	21,748	22,560	185,916	262,950
Operations and maintenance	111,749	127,934	318,763	329,581
Depreciation, depletion and amortization	72,802	60,814	199,559	185,025
Income taxes
Deferred			120,656	95,005
Taxes, other than income taxes	20,129	15,615	69,399	64,508
Accretion expense	1,728	1,561	5,066	4,568
Total operating expenses	228,156	228,484	778,703	846,632
Operating Income (Expense)	150,412	67,320	416,628	357,811
Other Income (Expense)
Interest expense	11,976	9,591	30,843	29,395
Other income	619	2,222	1,727	2,555
Other expense	(2,074)	(61)	(1,449)	(541)
Total other income (expense)	(13,431)	(7,430)	(30,565)	(27,381)
Interest Charges
Income Before Income Taxes	136,981	59,890	386,063	330,430
Income tax expense	49,382	21,586	140,871	119,873
Net Income (Loss)	87,599	38,304	245,192	210,557
Diluted Earnings Per Average Common Share (dollars per share)	$ 1.21	$ 0.53	$ 3.39	$ 2.92
Basic Earnings Per Average Common Share (dollars per share)	$ 1.22	$ 0.53	$ 3.40	$ 2.93
Dividends Per Common Share (dollars per share)	$ 0.135	$ 0.130	$ 0.405	$ 0.390
Diluted Average Common Shares Outstanding	72,375	72,070	72,409	72,061
Basic Average Common Shares Outstanding	72,068	71,854	72,045	71,838
Alabama Gas Corporation
Operating Revenues
Natural gas distribution	59,616	61,693	415,497	498,132
Operating Expenses
Cost of gas	21,748	22,560	185,916	262,950
Operations and maintenance	33,001	33,763	106,535	98,667
Depreciation, depletion and amortization	9,980	9,451	29,606	34,380
Income taxes
Current	(9,414)	(18,633)	3,456	1,821
Deferred	3,664	14,619	16,626	21,889
Taxes, other than income taxes	5,568	4,934	27,899	32,757
Total operating expenses	64,547	66,694	370,038	452,464
Operating Income (Expense)	(4,931)	(5,001)	45,459	45,668
Other Income (Expense)
Interest expense	3,835	3,253	10,988	10,243
Allowance for funds used during construction	260	280	652	550
Other income	326	891	941	1,184
Other expense	(913)	(37)	(720)	(373)
Total other income (expense)	(327)	1,134	873	1,361
Interest Charges
Interest on long-term debt	3,025	2,960	9,106	8,892
Other interest expense	810	293	1,882	1,351
Net Income (Loss)	$ (9,093)	$ (7,120)	$ 35,344	$ 36,786

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Reconciliation of Earnings Per Share (Details) - Antidilutive Securities	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010
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)	293,978	479,820	293,978	479,820
Non-vested restricted stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share (in options or shares)	0	0	0	0

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Financial Instruments (Details) (USD $)	9 Months Ended
	Sep. 30, 2011	Aug. 31, 2011 Senior Notes [Member]	Sep. 30, 2011 Alabama Gas Corporation	Dec. 31, 2010 Alabama Gas Corporation	Sep. 30, 2011 Alabama Gas Corporation Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Sep. 30, 2011 Alabama Gas Corporation Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure	Sep. 30, 2011 Long-term Debt, Including Current Portion, Fair Value, Fair Value Disclosure	Sep. 30, 2011 Long-term Debt, Including Current Portion, Carrying Value, Fair Value Disclosure
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt Instrument, Face Amount		$ 400,000,000
Debt Instrument, Interest Rate, Stated Percentage		4.625%
Long-term Debt, Fair Value					221,900,000	200,400,000	860,300,000	805,400,000
Financing Receivable			10,200,000	8,800,000
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			428,000
Financing Receivable, Allowance for Credit Losses [Roll Forward]
Allowance for credit losses, beginning balance	447,000
Provision	(24,000)
Allowance for credit losses, ending balance	$ 423,000

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Regulatory Assets and Liabilities (Details) (USD $) In Thousands	Sep. 30, 2011	Dec. 31, 2010
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 44,525	$ 28,286
Regulatory Assets, Noncurrent	109,244	105,365
Regulatory Liability, Current	51,849	75,703
Regulatory Liability, Noncurrent	87,579	110,447
Alabama Gas Corporation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	44,525	28,286
Regulatory Assets, Noncurrent	109,244	105,365
Regulatory Liability, Current	51,849	75,703
Regulatory Liability, Noncurrent	87,579	110,447
Alabama Gas Corporation | Enhanced stability reserve
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	0	3,794
Alabama Gas Corporation | Pension and postretirement assets
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	170	132
Regulatory Assets, Noncurrent	87,181	60,284
Alabama Gas Corporation | Accretion and depreciation for asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0	0
Regulatory Assets, Noncurrent	9,007	8,681
Alabama Gas Corporation | Risk management activities
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	44,137	27,906
Regulatory Assets, Noncurrent	13,050	32,461
Alabama Gas Corporation | RSE adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	25	25
Regulatory Assets, Noncurrent	0	0
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	193	223
Regulatory Assets, Noncurrent	6	145
Alabama Gas Corporation | RSE adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	5,068	4,147
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Unbilled service margin
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	5,143	34,197
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Postretirement liabilities
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	0	754
Alabama Gas Corporation | Gas supply adjustment
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	21,060	14,990
Regulatory Liability, Noncurrent	0	0
Alabama Gas Corporation | Asset removal costs, net
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	7,834	6,913
Alabama Gas Corporation | Asset retirement obligation
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	11,697	11,439
Alabama Gas Corporation | Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	20,545	22,336
Regulatory Liability, Noncurrent	67,237	90,504
Alabama Gas Corporation | Other
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	33	33
Regulatory Liability, Noncurrent	811	837
Refundable negative salvage
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	20,545
Regulatory Liability, Noncurrent	$ 67,237

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Segment Information (Details) (USD $) In Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2011	Sep. 30, 2010	Sep. 30, 2011	Sep. 30, 2010	Dec. 31, 2010
Segment Reporting Information, Profit (Loss)
Operating revenues	$ 378,568	$ 295,804	$ 1,195,331	$ 1,204,443
Operating income (loss)	150,412	67,320	416,628	357,811
Other income (expense)	(13,431)	(7,430)	(30,565)	(27,381)
Income before income taxes	136,981	59,890	386,063	330,430
Identifiable assets	4,875,442		4,875,442		4,363,560
Oil and Gas Operations
Segment Reporting Information, Profit (Loss)
Operating revenues	318,952	234,111	779,834	706,311
Operating income (loss)	161,331	76,644	351,808	289,385
Other income (expense)	(9,363)	(4,848)	(20,632)	(17,274)
Identifiable assets	3,752,437		3,752,437		3,160,601
Natural Gas Distribution
Segment Reporting Information, Profit (Loss)
Operating revenues	59,616	61,693	415,497	498,132
Operating income (loss)	(10,681)	(9,015)	65,541	69,378
Other income (expense)	(4,162)	(2,119)	(10,115)	(8,882)
Identifiable assets	1,107,188		1,107,188		1,166,899
Eliminations and other
Segment Reporting Information, Profit (Loss)
Operating income (loss)	(238)	(309)	(721)	(952)
Other income (expense)	94	(463)	182	(1,225)
Identifiable assets	$ 15,817		$ 15,817		$ 36,060