Energen (EGN) 10-Q 2010 Q3 Quarterly report

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, 2010

OR

¨ 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 ( )

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  ¨
Alabama Gas Corporation	YES  ¨	NO  ¨

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 filerx Accelerated filer¨ Non-accelerated filer¨ Smaller reporting company¨

Alabama Gas Corporation - Large accelerated filer¨ Accelerated filer¨ Non-accelerated filerx Smaller reporting company¨

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

Energen Corporation	YES  ¨	NO  x
Alabama Gas Corporation	YES  ¨	NO  x

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of November 1, 2010.

Energen Corporation	$0.01 par value	71,888,083 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, 2010

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		27
	Selected Business Segment Data of Energen Corporation		38
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		39
Item 4.	Controls and Procedures		40
	PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		41
Item 6.	Exhibits		41
SIGNATURES			42

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

ENERGEN CORPORATION

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
(in thousands, except per share data)	2010			2009			2010			2009
Operating Revenues
Oil and gas operations	$	234,111		$	218,501		$	706,311		$	606,158
Natural gas distribution		61,693			68,788			498,132			471,457
Total operating revenues		295,804			287,289			1,204,443			1,077,615
Operating Expenses
Cost of gas		22,560			29,377			262,950			232,283
Operations and maintenance		127,934			97,963			329,581			274,850
Depreciation, depletion and amortization		60,814			61,323			185,025			172,308
Taxes, other than income taxes		15,615			15,471			64,508			57,099
Accretion expense		1,561			1,306			4,568			3,605
Total operating expenses		228,484			205,440			846,632			740,145
Operating Income		67,320			81,849			357,811			337,470
Other Income (Expense)
Interest expense		(9,591	)		(10,017	)		(29,395	)		(29,586	)
Other income		2,222			2,536			2,555			4,058
Other expense		(61	)		(229	)		(541	)		(589	)
Total other expense		(7,430	)		(7,710	)		(27,381	)		(26,117	)
Income Before Income Taxes		59,890			74,139			330,430			311,353
Income tax expense		21,586			27,018			119,873			113,649
Net Income	$	38,304		$	47,121		$	210,557		$	197,704
Diluted Earnings Per Average Common Share	$	0.53		$	0.65		$	2.92		$	2.75
Basic Earnings Per Average Common Share	$	0.53		$	0.66		$	2.93		$	2.76
Dividends Per Common Share	$	0.13		$	0.125		$	0.39		$	0.375
Diluted Average Common Shares Outstanding		72,070			71,996			72,061			71,878
Basic Average Common Shares Outstanding		71,854			71,651			71,838			71,641

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

3

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

(in thousands)	September 30, 2010		December 31, 2009
ASSETS
Current Assets
Cash and cash equivalents	$	14,114	$	75,844
Short-term investments		74,982		-
Accounts receivable, net of allowance for doubtful accounts of $18,145 at September 30, 2010, and $17,251 at December 31, 2009		225,996		327,163
Inventories
Storage gas inventory		47,705		42,475
Materials and supplies		20,945		17,440
Liquified natural gas in storage		3,172		3,409
Regulatory asset		42,858		33,196
Income tax receivable		52,836		4,552
Prepayments and other		11,724		11,527
Total current assets		494,332		515,606
Property, Plant and Equipment
Oil and gas properties, successful efforts method		3,752,820		3,379,128
Less accumulated depreciation, depletion and amortization		1,111,395		972,676
Oil and gas properties, net		2,641,425		2,406,452
Utility plant		1,276,986		1,211,624
Less accumulated depreciation		508,054		489,924
Utility plant, net		768,932		721,700
Other property, net		17,711		16,317
Total property, plant and equipment, net		3,428,068		3,144,469
Other Assets
Regulatory asset		139,406		102,133
Long-term derivative instruments		8,094		7,824
Pension assets		260		-
Deferred charges and other		33,592		33,086
Total other assets		181,352		143,043
TOTAL ASSETS	$	4,103,752	$	3,803,118

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, 2010			December 31, 2009
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	155,000		$	150,000
Notes payable to banks		42,000			-
Accounts payable		171,388			164,327
Accrued taxes		65,669			49,884
Customers’ deposits		18,190			20,836
Amounts due customers		16,832			24,106
Accrued wages and benefits		19,642			27,347
Regulatory liability		53,216			29,719
Royalty payable		20,293			19,034
Deferred income taxes		4,889			10,015
Other		29,837			25,493
Total current liabilities		596,956			520,761
Long-term debt		405,230			410,786
Deferred Credits and Other Liabilities
Asset retirement obligation		95,460			88,298
Pension and other postretirement liabilities		52,209			55,899
Regulatory liability		112,270			155,088
Long-term derivative instruments		71,454			60,446
Deferred income taxes		592,063			505,460
Other		11,339			18,137
Total deferred credits and other liabilities		934,795			883,328
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, 74,778,976 shares issued at September 30, 2010, and 74,593,431 shares issued at December 31, 2009		748			746
Premium on capital stock		467,674			461,661
Capital surplus		2,802			2,802
Retained earnings		1,809,280			1,626,753
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net		47,632			49,405
Pension and postretirement plans		(37,210	)		(31,790	)
Deferred compensation plan		3,978			3,121
Treasury stock, at cost; 3,051,336 shares at September 30, 2010, and 2,991,373 shares at December 31, 2009		(128,133	)		(124,455	)
Total shareholders’ equity		2,166,771			1,988,243
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	4,103,752		$	3,803,118

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

5

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

ENERGEN CORPORATION

(Unaudited)

Nine months ended September 30,(in thousands)	2010			2009
Operating Activities
Net income	$	210,557		$	197,704
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		185,025			172,308
Accretion expense		4,568			3,605
Deferred income taxes		95,005			74,196
Bad debt expense		2,969			6,621
Exploratory expense		53,642			1,102
Change in derivative fair value		278			(913	)
Gain on sale of assets		(529	)		(5,392	)
Other, net		(4,849	)		4,334
Net change in:
Accounts receivable		51,577			91,344
Inventories		(8,498	)		9,513
Accounts payable		(15,449	)		(61,026	)
Amounts due customers including gas supply pass-through		22,076			8,072
Income tax receivable		(48,284	)		46,822
Pension and other postretirement benefit contributions		(40,988	)		(22,776	)
Other current assets and liabilities		10,839			6,075
Net cash provided by operating activities		517,939			531,589
Investing Activities
Additions to property, plant and equipment		(309,849	)		(266,674	)
Acquisitions, net of cash acquired		(208,667	)		(185,645	)
Proceeds from sale of assets		607			7,426
Purchase of short-term investments		(154,880	)		-
Sale of short-term investments		79,938			-
Other, net		(1,395	)		(1,450	)
Net cash used in investing activities		(594,246	)		(446,343	)
Financing Activities
Payment of dividends on common stock		(28,030	)		(26,575	)
Issuance of common stock		594			464
Payment of long-term debt		(707	)		(776	)
Net change in short-term debt		42,000			(57,000	)
Tax benefit on stock compensation		720			317
Net cash (used in) provided by financing activities		14,577			(83,570	)
Net change in cash and cash equivalents		(61,730	)		1,676
Cash and cash equivalents at beginning of period		75,844			13,177
Cash and Cash Equivalents at End of Period	$	14,114		$	14,853

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 September 30,						Nine months ended September 30,
(in thousands)	2010			2009			2010			2009
Operating Revenues	$	61,693		$	68,788		$	498,132		$	471,457
Operating Expenses
Cost of gas		22,560			29,377			262,950			232,283
Operations and maintenance		33,763			35,579			98,667			99,871
Depreciation and amortization		9,451			12,850			34,380			38,119
Income taxes
Current		(18,633	)		(12,475	)		1,821			8,248
Deferred		14,619			5,835			21,889			14,663
Taxes, other than income taxes		4,934			6,219			32,757			32,340
Total operating expenses		66,694			77,385			452,464			425,524
Operating Income (Loss)		(5,001	)		(8,597	)		45,668			45,933
Other Income (Expense)
Allowance for funds used during construction		280			370			550			920
Other income		891			1,040			1,184			1,594
Other expense		(37	)		(178	)		(373	)		(521	)
Total other income		1,134			1,232			1,361			1,993
Interest Charges
Interest on long-term debt		2,960			2,975			8,892			8,935
Other interest expense		293			406			1,351			1,359
Total interest charges		3,253			3,381			10,243			10,294
Net Income (Loss)	$	(7,120	)	$	(10,746	)	$	36,786		$	37,632

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

7

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

(in thousands)	September 30, 2010			December 31, 2009
ASSETS
Property, Plant and Equipment
Utility plant	$	1,276,986		$	1,211,624
Less accumulated depreciation		508,054			489,924
Utility plant, net		768,932			721,700
Other property, net		44			146
Current Assets
Cash and cash equivalents		7,329			9,460
Accounts receivable
Gas		49,885			137,891
Other		10,413			8,617
Affiliated companies		2,796			-
Allowance for doubtful accounts		(17,300	)		(16,400	)
Inventories
Storage gas inventory		47,705			42,475
Materials and supplies		4,163			4,374
Liquified natural gas in storage		3,172			3,409
Deferred income taxes		24,483			25,896
Income tax receivable		11,459			3,469
Regulatory asset		42,858			33,196
Prepayments and other		5,542			3,303
Total current assets		192,505			255,690
Other Assets
Regulatory asset		139,406			102,133
Pension assets		161			-
Deferred charges and other		4,556			4,997
Total other assets		144,123			107,130
TOTAL ASSETS	$	1,105,604		$	1,084,666

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, 2010		December 31, 2009
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, 2010 and December 31, 2009		20		20
Premium on capital stock		31,682		31,682
Capital surplus		2,802		2,802
Retained earnings		282,718		283,299
Total common shareholder’s equity		317,222		317,803
Long-term debt		200,815		206,522
Total capitalization		518,037		524,325
Current Liabilities
Long-term debt due within one year		5,000		-
Notes payable to banks		42,000		-
Accounts payable		78,431		78,154
Affiliated companies		-		24,962
Accrued taxes		50,482		35,314
Customers’ deposits		18,190		20,836
Amounts due customers		16,832		24,106
Accrued wages and benefits		8,520		11,472
Regulatory liability		53,216		29,719
Other		11,376		9,830
Total current liabilities		284,047		234,393
Deferred Credits and Other Liabilities
Deferred income taxes		131,998		121,826
Pension and other postretirement liabilities		16,763		19,054
Regulatory liability		112,270		155,088
Long-term derivative instruments		39,405		18,965
Other		3,084		11,015
Total deferred credits and other liabilities		303,520		325,948
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,105,604	$	1,084,666

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)	2010			2009
Operating Activities
Net income	$	36,786		$	37,632
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		34,380			38,119
Deferred income taxes		21,889			14,663
Bad debt expense		2,979			6,552
Other, net		(16,188	)		6,281
Net change in:
Accounts receivable		40,921			67,687
Inventories		(4,782	)		15,989
Accounts payable		(16,381	)		(52,313	)
Amounts due customers including gas supply pass-through		22,076			8,072
Income tax receivable		(7,990	)		27,237
Pension and other postretirement benefit contributions		(25,185	)		(13,718	)
Other current assets and liabilities		8,917			(6,478	)
Net cash provided by operating activities		97,422			149,723
Investing Activities
Additions to property, plant and equipment		(74,710	)		(55,908	)
Other, net		(3,807	)		(1,091	)
Net cash used in investing activities		(78,517	)		(56,999	)
Financing Activities
Dividends		(37,367	)		(26,890	)
Payment of long-term debt		(707	)		(776	)
Net decreases in advances from affiliates		(24,962	)		(9,366	)
Net change in short-term debt		42,000			(57,000	)
Net cash used in financing activities		(21,036	)		(94,032	)
Net change in cash and cash equivalents		(2,131	)		(1,308	)
Cash and cash equivalents at beginning of period		9,460			9,728
Cash and Cash Equivalents at End of Period	$	7,329		$	8,420

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, 2009, 2008 and 2007 included in the 2009 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. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

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 current and prior quarterly results, the prior year-end results, and the anticipated results of Alagasco and Energen for the year ended December 31, 2010 and determined that the amount was not material to these periods. As a result, the Company corrected this error in the first quarter of 2010.

2. SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents:All highly liquid financial instruments with an original maturity of three months or less at the time of purchase are considered to be cash or cash equivalents. The Company maintains sweep accounts with financial institutions in which the account balances are invested overnight in repurchase agreements collateralized at 102 percent by United States (U.S.) Government Securities. As of September 30, 2010, Energen had $0.5 million of repurchase agreements included in cash and cash equivalents. The Company has deposits with certain financial institutions which exceed federally insured limits. The Company has reviewed the credit risk associated with these deposits and believes there is minimal risk of a material loss.

Short-Term Investments: All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short term investments. As of September 30, 2010, Energen had $75 million of U.S. Treasury bills classified as short term investments which mature on December 9, 2010. Short-term investments are classified as Level 2 fair value.

Utility Plant and Depreciation: 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 revised depreciation rates decreased depreciation expense by approximately $3.9 million and $5.3 million for the three months and nine months ended September 30, 2010, respectively. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million in July, 2010 and will return to eligible customers an additional estimated $115.5 million, which includes approximately $23.1 million between December 1, 2010 and March 31, 2011. The remainder will be refunded to 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 Enhanced Stability Reserve (ESR) and other commission-approved charges. On November 1, 2010, the APSC specifically approved adjustments to the total amount refundable to include items originally approved in the APSC’s 1998 order establishing the ESR, environmental response costs

11

and self insurance costs above $1 million per occurrence. The refund in July, 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 past five years. Approved depreciation rates averaged approximately 3.8 percent and 4.4 percent in the nine months ended September 30, 2010 and 2009, respectively.

3. REGULATORY MATTERS

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

Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the 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 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 nine months ended September 30, 2010, Alagasco had a $10.6 million pre-tax reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. As of September 30, 2009, Alagasco had a $1.5 million pre-tax reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. A $10.2 million and $24.7 million annual increase in revenues became effective December 1, 2009 and 2008, 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, 2010 and 2009.

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; and (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses caused Alagasco’s year-end return on average 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 future removal costs that are being refunded to customers over the nine year period the amount necessary to clear the debit balance in the ESR each

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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 future removal 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 self insurance costs above $1 million per occurrence. In addition, the APSC raised the thresholds on items that can be charged to the ESR as follows: (1) extraordinary O&M expenses, other than 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 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) individual large commercial and industrial customer revenue 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 (RCE) 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 individual industrial and commercial customer revenue losses 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.

In connection with the above, Alagasco expects to recover certain manufactured gas plant site remediation costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory account of $2.7 million as of September 30, 2010 and December 31, 2009, as more fully described in Note 10, Commitments and Contingencies.

4. 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 that qualify as cash flow hedges 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 natural gas and crude oil over-the-counter (OTC) swaps, collars 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 seven of its active counterparties and in a net loss position with the remaining two at September 30, 2010. The following counterparties, Bank of Montreal, J Aron & Company, Morgan Stanley Capital Group, Inc., Barclays Bank PLC, BP Corporation North America, Inc. and Merrill Lynch Commodities, Inc., represented approximately 22 percent, 21 percent, 19 percent, 19 percent, 15 percent and 13 percent, respectively, of Energen Resources’ net gain on fair value of derivatives.

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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, 2010, 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, but not all, 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 may also enter 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, 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 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, 2010
	Oil and Gas Operations			Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	134,247		$	-		$	134,247
Long-term asset derivative instruments		19,224			-			19,224
Total derivative assets		153,471			-			153,471
Accounts receivable		(26,410	)*		-			(26,410	)
Accounts payable		(3,073	)		-			(3,073	)
Long-term asset derivative instruments		(11,100	)*		-			(11,100	)
Long-term liability derivative instruments		(32,049	)		-			(32,049	)
Total derivative liabilities		(72,632	)		-			(72,632	)
Total derivatives designated		80,839			-			80,839
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable		(81	)*		-			(81	)
Long-term asset derivative instruments		(30	)*		-			(30	)
Total derivative assets		(111	)		-			(111	)
Accounts payable		-			(41,948	)		(41,948	)
Long-term liability derivative instruments		-			(39,405	)		(39,405	)
Total derivative liabilities		-			(81,353	)		(81,353	)
Total derivatives not designated		(111	)		(81,353	)		(81,464	)
Total derivatives	$	80,728		$	(81,353	)	$	(625	)

(in thousands)	December 31, 2009
	Oil and Gas Operations			Natural Gas Distribution		Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	148,937		$	-	$	148,937
Long-term asset derivative instruments		16,164			-		16,164
Total derivative assets		165,101			-		165,101
Accounts receivable		(29,484	)*		-		(29,484	)
Accounts payable		(6,352	)		-		(6,352	)
Long-term asset derivative instruments		(8,340	)*		-		(8,340	)
Long-term liability derivative instruments		(41,374	)		-		(41,374	)
Total derivative liabilities		(85,550	)		-		(85,550	)
Total derivatives designated		79,551			-		79,551

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Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable		(10	)*		-			(10	)
Accounts payable		-			(25,750	)		(25,750	)
Long-term liability derivative instruments		(106	)		(18,965	)		(19,071	)
Total derivative liabilities		(116	)		(44,715	)		(44,831	)
Total derivatives not designated		(116	)		(44,715	)		(44,831	)
Total derivatives	$	79,435		$	(44,715	)	$	34,720

* 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 $29.2 million and a net $30.3 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in OCI as of September 30, 2010 and December 31, 2009, 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 of Gain (Loss) on Income Statement		Three months ended September 30, 2010			Three months ended September 30, 2009
Loss recognized in OCI on derivative (effective portion), net of tax of ($4.4) million and ($0.5) million		-	$	(7,244	)	$	(774	)
Gain reclassified from accumulated OCI into income (effective portion)		Operating revenues	$	56,456		$	61,114
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)		Operating revenues	$	(1,861	)	$	754

(in thousands)	Location of Gain (Loss) on Income Statement		Nine months ended September 30, 2010		Nine months ended September 30, 2009
Gain recognized in OCI on derivative (effective portion), net of tax of $55.9 million and $15.9 million		-	$	91,141	$	25,872
Gain reclassified from accumulated OCI into income (effective portion)		Operating revenues	$	149,845	$	200,672
Gain recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)		Operating revenues	$	18	$	262

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

(in thousands)	Location of Gain (Loss) on Income Statement		Three months ended September 30, 2010		Three months ended September 30, 2009
Gain (loss) recognized in income on derivative		Operating revenues	$	-	$	409

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(in thousands)	Location of Gain (Loss) on Income Statement		Nine months ended September 30, 2010			Nine months ended September 30, 2009
Gain (loss) recognized in income on derivative		Operating revenues	$	(4	)	$	850

As of September 30, 2010, $62 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, 2010, the Company had 12 thousand barrels (MBbl) of oil hedges which expire during 2011 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 2010 and subsequent years:

Production     Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2010	3.5 Bcf	$8.79 Mcf	NYMEX Swaps
	9.4 Bcf	$7.23 Mcf	Basin Specific Swaps
2011	13.1 Bcf	$6.66 Mcf	NYMEX Swaps
	25.7 Bcf	$6.36 Mcf	Basin Specific Swaps
Oil
2010	973 MBbl	$86.65 Bbl	NYMEX Swaps
2011	3,729 MBbl	$77.26 Bbl	NYMEX Swaps
2012	3,337 MBbl	$81.63 Bbl	NYMEX Swaps
2013	1,608 MBbl	$81.43 Bbl	NYMEX Swaps
2014	1,176 MBbl	$84.14 Bbl	NYMEX Swaps
Oil Basis Differential
2010	574 MBbl	*	Basis Swaps
2011	2,076 MBbl	*	Basis Swaps
2012	672 MBbl	*	Basis Swaps
Natural Gas Liquids
2010	9.3 MMGal	$0.88 Gal	Liquids Swaps
2011	38.9 MMGal	$0.89 Gal	Liquids Swaps
2012	36.4 MMGal	$0.85 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 2010 and subsequent years:
Production     Period	Total Hedged Volumes		Description
2010	6.1 Bcf		NYMEX Swaps
2011	15.2 Bcf		NYMEX Swaps
2012	17.2 Bcf		NYMEX Swaps
2013	1.5 Bcf		NYMEX Swaps

As of September 30, 2010, 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;

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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 assumptions 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, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	32,247		$	75,509		$	107,756
Noncurrent assets		(4,000	)		12,094			8,094
Current liabilities		(44,861	)		(160	)		(45,021	)
Noncurrent liabilities		(70,888	)		(566	)		(71,454	)
Net derivative asset (liability)	$	(87,502	)	$	86,877		$	(625	)

	December 31, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	57,235		$	62,208		$	119,443
Noncurrent assets		(1,600	)		9,424			7,824
Current liabilities		(25,518	)		(6,584	)		(32,102	)
Noncurrent liabilities		(59,914	)		(531	)		(60,445	)
Net derivative asset (liability)	$	(29,797	)	$	64,517		$	34,720

* 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, 2010, Alagasco had $41.9 million and $39.4 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, 2009, Alagasco had $25.8 million and $19 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, 2010 and December 31, 2009.

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

(in thousands)	Three months ended September 30, 2010			Three months ended September 30, 2009
Balance at beginning of period	$	91,817		$	144,883
Realized gains		(455	)		(1,489	)
Unrealized gains (losses) relating to instruments held at the reporting date		26,282			(14,166	)
Purchases and settlements during period		(30,767	)		(40,062	)
Balance at end of period	$	86,877		$	89,166

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(in thousands)	Nine months ended September 30, 2010			Nine months ended September 30, 2009
Balance at beginning of period	$	64,517		$	154,094
Realized gains		(455	)		(1,489	)
Unrealized gains (losses) relating to instruments held at the reporting date		102,169			60,245
Purchases and settlements during period		(79,354	)		(123,684	)
Balance at end of period	$	86,877		$	89,166

5. RECONCILIATION OF EARNINGS PER SHARE (EPS)

(in thousands, except per share amounts)	Three months ended September 30, 2010						Three months ended September 30, 2009
	Net Income		Shares		Per Share Amount		Net Income		Shares		Per Share Amount
Basic EPS	$	38,304		71,854	$	0.53	$	47,121		71,651	$	0.66
Effect of dilutive securities
Performance share awards				-						107
Stock options				199						188
Non-vested restricted stock				17						50
Diluted EPS	$	38,304		72,070	$	0.53	$	47,121		71,996	$	0.65

(in thousands, except per share amounts)	Nine months ended September 30, 2010						Nine months ended September 30, 2009
	Net Income		Shares		Per Share Amount		Net Income		Shares		Per Share Amount
Basic EPS	$	210,557		71,838	$	2.93	$	197,704		71,641	$	2.76
Effect of dilutive securities
Performance share awards				-						103
Stock options				206						88
Non-vested restricted stock				17						46
Diluted EPS	$	210,557		72,061	$	2.92	$	197,704		71,878	$	2.75

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, as their effect was non-dilutive. For the three months and nine months ended September 30, 2009, the Company had 198,710 and 969,487, respectively, options that were excluded from the computation of diluted EPS. For the three months and nine months ended September 30, 2010, the Company had no shares of non-vested restricted stock that were excluded from the computation of diluted EPS. For the three months and nine months ended September 30, 2009, the Company had 6,150 shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

6. 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).

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	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2010			2009			2010			2009
Operating revenues
Oil and gas operations	$	234,111		$	218,501		$	706,311		$	606,158
Natural gas distribution		61,693			68,788			498,132			471,457
Total	$	295,804		$	287,289		$	1,204,443		$	1,077,615
Operating income (loss)
Oil and gas operations	$	76,644		$	97,682		$	289,385		$	270,277
Natural gas distribution		(9,015	)		(15,237	)		69,378			68,844
Eliminations and corporate expenses		(309	)		(596	)		(952	)		(1,651	)
Total	$	67,320		$	81,849		$	357,811		$	337,470
Other income (expense)
Oil and gas operations	$	(4,848	)	$	(5,343	)	$	(17,274	)	$	(17,507	)
Natural gas distribution		(2,119	)		(2,149	)		(8,882	)		(8,301	)
Eliminations and other		(463	)		(218	)		(1,225	)		(309	)
Total	$	(7,430	)	$	(7,710	)	$	(27,381	)	$	(26,117	)
Income before income taxes	$	59,890		$	74,139		$	330,430		$	311,353

(in thousands)	September 30, 2010		December 31, 2009
Identifiable assets
Oil and gas operations	$	2,920,881	$	2,654,068
Natural gas distribution		1,102,808		1,084,666
Subtotal		4,023,689		3,738,734
Eliminations and other		80,063		64,384
Total	$	4,103,752	$	3,803,118

7. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended September 30,
(in thousands)	2010			2009
Net income	$	38,304		$	47,121
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($4.4) million and ($0.5) million		(7,244	)		(774	)
Reclassification adjustment for derivative instruments, net of tax of ($20.7) million and ($23.5) million		(33,849	)		(38,358	)
Pension and postretirement plans, net of tax of ($3.6) million and ($1.5) million		(6,678	)		(2,729	)
Comprehensive income (loss)	$	(9,467	)	$	5,260

	Nine months ended September 30,
(in thousands)	2010			2009
Net income	$	210,557		$	197,704
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $55.9 million and $15.9 million		91,141			25,872
Reclassification adjustment for derivative instruments, net of tax of ($56.9) million and ($76.4) million		(92,914	)		(124,578	)
Pension and postretirement plans, net of tax of ($2.9) million and ($0.9) million		(5,420	)		(1,712	)
Comprehensive income	$	203,364		$	97,286

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(in thousands)	September 30, 2010			December 31, 2009
Unrealized gain on hedges, net of tax of $29.2 million and $30.3 million	$	47,632		$	49,405
Pension and postretirement plans, net of tax of ($20) million and ($17.1) million		(37,210	)		(31,790	)
Accumulated other comprehensive income	$	10,422		$	17,615

8. STOCK COMPENSATION

1997 Stock Incentive Plan

The 1997 Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the 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 281,110 non-qualified option shares during the first quarter of 2010 with a grant-date fair value of $16.47.

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 171,749 awards during the first quarter of 2010. These awards had a fair value of $15.24 as of September 30, 2010.

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 2010, Energen Resources awarded 2,442 Petrotech units with a three year vesting period. These awards had a fair value of $44.57 as of September 30, 2010.

1997 Deferred Compensation Plan

During the three months and nine months ended September 30, 2010, the Company had noncash purchases of approximately $11,000 and $2.3 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.

9. 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)	2010			2009			2010			2009
Components of net periodic benefit cost:
Service cost	$	2,144		$	1,835		$	6,430		$	5,505
Interest cost		2,841			3,016			8,524			9,048
Expected long-term return on assets		(3,229	)		(3,501	)		(9,686	)		(10,502	)
Actuarial loss		1,443			997			4,330			2,991
Prior service cost amortization		124			145			372			434
Termination benefit charge		-			-			-			145
Net periodic expense	$	3,323		$	2,492		$	9,970		$	7,621

In March 2010 and April 2010, the Company made contributions of $2.3 million and $0.6 million, respectively, to the assets of the defined benefit qualified pension plans. In May 2010, the Company made additional required contributions of approximately $6.9 million and additional discretionary contributions of approximately $24.3 million to the defined benefit qualified pension plans. The Company made discretionary contributions of approximately $1 million in June 2010 to the defined benefit qualified pension plans. No additional discretionary

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contributions are currently anticipated to be made to the pension plans during 2010. For the three months and nine months ending September 30, 2010, the Company made benefit payments aggregating $44,000 and $2.2 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $50,000 through the remainder of 2010.

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)	2010			2009			2010			2009
Components of net periodic benefit cost:
Service cost	$	516		$	453		$	1,548		$	1,360
Interest cost		1,208			1,212			3,625			3,637
Expected long-term return on assets		(996	)		(885	)		(2,990	)		(2,657	)
Actuarial loss		-			57			-			171
Transition amortization		479			479			1,438			1,438
Net periodic expense	$	1,207		$	1,316		$	3,621		$	3,949

For the three months and nine months ended September 30, 2010, the Company made contributions aggregating $1.2 million and $3.6 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $1.2 million to postretirement benefit plan assets through the remainder of 2010. 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.

10. 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 $166 million through September 2024. During the nine months ending September 30, 2010 and 2009, Alagasco recognized approximately $38.1 million and $35.1 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 243 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, 2010, the fixed price purchases under these guarantees had a maximum term outstanding through October 2011 and an aggregate purchase price of $4.4 million with a market value of $3.7 million.

Income Taxes:Energen and its subsidiaries’ 2007 and 2008 federal consolidated income tax returns are currently 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. Although the timing of income tax audit resolutions is highly uncertain, an unfavorable outcome in this matter would result in income tax cash payments of approximately $31 million. The Company has appropriately reflected this potential payment in deferred tax liabilities.

The Company has on-going income tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur within the next twelve months as a result of the completion of various audits and the expiration of statute of limitations. The change of the unrecognized tax benefits could have a material impact to the Company’s effective tax rate. The

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timing and outcome of these tax examinations is highly uncertain. During the quarter, the Company recognized a $2.4 million benefit associated with the release of an unrecognized income tax benefit liability. The Company reassessed its measurement due to recent developments related to the issue and now believes that the full amount of the tax benefit has a greater than 50% chance of being fully realized.

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.

Legacy Litigation:During recent years, numerous lawsuits have been filed against oil production companies in Louisiana for restoration of oilfield properties. These suits are referred to in the industry as “legacy litigation” because they usually involve operations that were conducted on the affected properties many years earlier. Energen Resources is or has been a party to several legacy litigation lawsuits, most of which result from the operations of predecessor companies. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from legacy litigation in excess of the Company’s accrued provision for estimated liability are not considered material to the Company’s financial position.

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

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. Remediation of the Huntsville, Alabama manufactured gas plant site, as discussed below, may also result in unanticipated costs.

A discussion of certain litigation in the state of Louisiana related to the restoration of oilfield properties is included above under Legal Matters.

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 with such sale being approved by the APSC. While Alagasco no longer owns the Huntsville site, the Company and the current site owner have entered into a Consent Order and agreed to develop an action plan for the site. Based on the limited information available at this time, Alagasco preliminarily estimates that it may incur costs associated with the site ranging from $3 million to $6.1 million. At the present time, the Company cannot conclude that any amount within this range is a better estimate than any other. During the three months and nine months ended September 30, 2010, the Company incurred costs of $0.1 million and $0.3 million, respectively, associated with the site. As of September 30, 2010, the Company has accrued a contingent liability of $2.5 million in addition to the costs previously incurred. The estimate assumes an action plan for excavation of affected soil and sediment only. If it is determined that a greater scope of work is appropriate, then actual costs will likely exceed the preliminary estimate. Alagasco expects to recover such costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

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Other: 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 of federal oil and gas leases located 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 US federal leases. The Department proposes a change in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases. Such proposal, if determined appropriate, will result in increases of royalties due under the audit periods.

The Department’s preliminary findings are contrary to those allowed under previous audits and are inconsistent with the Company’s understanding of industry practice. The Company intends to vigorously contest the proposal under the preliminary findings and has requested additional information from the Department to determine the basis of its conclusion. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this finding and no amount has been accrued as of September 30, 2010.

11. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, approximates $607.6 million and has a carrying value of $561 million at September 30, 2010. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, approximates $217 million and has a carrying value of $206 million at September 30, 2010. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating.

On October 29, 2010, Energen and Alagasco entered into an $850 million and a $150 million, respectively, three-year syndicated unsecured credit facility (credit facilities) with domestic and foreign lenders. These 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.

12. REGULATORY ASSETS AND LIABILITIES

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

	September 30, 2010				December 31, 2009
(in thousands)	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	132	$	82,276	$	132	$	66,552
Accretion and depreciation for asset retirement obligation		-		14,821		-		13,566
Gas supply adjustment		-		-		7,059		-
Risk management activities		41,948		39,405		25,750		18,965
RSE adjustment		552		-		25		-
Enhanced stability reserve		-		2,706		-		2,706
Other		226		198		230		344
Total regulatory assets	$	42,858	$	139,406	$	33,196	$	102,133
Regulatory liabilities:
RSE adjustment	$	8	$	-	$	1,508	$	-
Unbilled service margin		5,758		-		28,178		-
Gas supply adjustment		24,314		-		-		-
Asset removal costs, net		-		494		-		136,799
Negative salvage refund*		23,103		92,411		-		-
Asset retirement obligation		-		18,520		-		17,419
Other		33		845		33		870
Total regulatory liabilities	$	53,216	$	112,270	$	29,719	$	155,088

* As of September 30, 2010, the Company reclassified $23.1 million and $92.4 million of accumulated asset removal costs to negative salvage refund 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 as discussed in Note 2, Significant Accounting Policies.

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13. 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, 2010, 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, 2009	$	88,298
Liabilities incurred		3,049
Liabilities settled		(455	)
Accretion expense		4,568
Balance of ARO as of September 30, 2010	$	95,460

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exist. Alagasco recorded a conditional asset retirement obligation, on a discounted basis of $18.5 million and $17.4 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of September 30, 2010 and December 31, 2009, respectively. The costs associated with asset retirement obligations are currently either being recovered in rates or are probable of recovery in future rates.

Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. Regulatory liabilities for accumulated asset removal costs of $0.5 million and $136.8 million for September 30, 2010 and December 31, 2009, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets. As of September 30, 2010, the Company reclassified $23.1 million and $92.4 million of accumulated asset removal costs to negative salvage refund 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 as discussed in Note 2, Significant Accounting Policies.

14. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

On October 29, 2010, Energen signed a purchase and sale agreement to buy interests in certain oil properties in the Permian Basin for a cash purchase price of $75 million (subject to closing adjustments). This purchase is expected to close during the fourth quarter and will have an effective date of December 1, 2010. Energen will acquire total estimated proved reserves of approximately 7.6 million barrels of oil equivalents (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 will use its credit facilities and internally generated cash flows to finance the acquisition.

In the third quarter of 2010, Energen Resources incurred a write-off of unproved capitalized leasehold costs associated with the remainder of its Alabama shale acreage. The non-cash charge totaled $23.4 million pre-tax and was charged to exploration expense, which is included in O&M expense, after the Company determined that the flow rates were insufficient to support economic development. During the second quarter of 2010, Energen Resources wrote off unproved leasehold costs associated with the deep Conasauga shale acreage as efforts indicated that it is not economically viable given associated capital costs and the outlook for natural gas prices. The non-cash costs of approximately $16.1 million pre-tax were charged to exploration expense. 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.

On September 30, 2010, Energen completed the purchase of certain oil properties in the Permian Basin for a cash price of $189 million (subject to closing adjustments). 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.

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The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed recognized as of September 30, 2010. The purchase price allocation is preliminary and subject to adjustment as the final closing statement is not complete.

(in thousands)
Consideration given
Cash (net)	$	188,531
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	152,050
Unproved leasehold properties		35,360
Accounts receivable		1,375
Asset retirement obligation		(142	)
Accounts payable		(112	)
Total identifiable net assets	$	188,531

In September 2009, Energen Resources recorded a $4.9 million pre-tax gain in other operating revenues from the sale of certain oil properties in the Permian Basin. The Company received approximately $6.5 million pre-tax in cash from the sale of this property.

On June 30, 2009, Energen completed the purchase of certain oil properties in the Permian Basin from Range Resources for a cash price of $181 million. This purchase had an effective date of May 1, 2009. Energen acquired proved reserves of approximately 15.2 MMBOE. Of the proved reserves acquired, an estimated 24 percent are undeveloped. Approximately 76 percent of the proved reserves are oil, 16 percent are natural gas liquids and natural gas comprises the remaining 8 percent. Energen Resources used its short-term credit facilities and internally generated cash flows to finance the acquisition.

The following table summarizes the consideration paid for Range Resources and the amounts of the assets acquired and liabilities assumed recognized as of June 30, 2009 (including the effects of closing adjustments).

(in thousands)
Consideration given to Range Resources
Cash (net)	$	181,249
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved properties	$	182,668
Unproved leasehold properties		3,800
Accounts receivable		4,987
Inventory and other		455
Asset retirement obligation		(6,590	)
Environmental liabilities		(3,124	)
Accounts payable		(947	)
Total identifiable net assets	$	181,249

Summarized below are the consolidated results of operations for the nine months ended September 30, 2009, on an unaudited pro forma basis as if the acquisition had occurred at the beginning of the period presented. The pro forma information is based on the Company’s consolidated results of operations for the nine months ended September 30, 2009, and on the data provided by the seller. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor are they indicative of results of the future operations of the combined enterprises.

(in thousands)	Nine months ended September 30, 2009
Operating revenues	$	1,096,190
Operating income	$	341,701

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15. RECENTLY ISSUED ACCOUNTING STANDARDS

On January 1, 2010, the Company adopted an accounting standard update to improve financial reporting by companies involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. This standard did not have an impact on the consolidated condensed financial statements of the Company.

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. This standard did not have an impact on the consolidated condensed financial statements of the Company.

On January 1, 2010, the Company adopted ASU No. 2010-07, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements, which eliminates the requirements for SEC filers to disclose the date through which it has evaluated subsequent events. This standard did not have a material impact on the consolidated condensed financial statements of the Company.

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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 $38.3 million ($0.53 per diluted share) for the three months ended September 30, 2010 compared with net income of $47.1 million ($0.65 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, 2010, of $46.3 million as compared with $59 million in the same quarter in the previous year. Significantly higher commodity prices (approximately $16 million after-tax) and decreased administrative expense (approximately $2 million after-tax) were more than offset by decreased production volumes (approximately $3 million after-tax), increased depreciation, depletion and amortization (DD&A) expense (approximately $2 million after-tax), increased lease operating expense (approximately $1 million after-tax) and higher exploration expense (approximately $21 million after-tax) due to a non-cash write-off of $14.6 million after-tax (approximately $0.20 per diluted share) of unproved leasehold costs associated with the remainder of its Alabama shale acreage combined with a related $6.7 million write-off of well costs. Energen Resources also reported an after-tax gain of $3.1 million on the sale of certain oil properties in the Permian Basin during the third quarter of 2009. Energen’s natural gas utility, Alagasco, reported a net loss of $7.1 million in the third quarter of 2010 compared to a net loss of $10.7 million in the same period last year, primarily due to the utility’s ability to earn on a higher level of equity and lower depreciation expense due to the Alabama Public Service Commission (APSC) approved reduction in depreciation rates.

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For the 2010 year- to- date, Energen’s net income totaled $210.6 million ($2.92 per diluted share) and compared favorably to net income of $197.7 million ($2.75 per diluted share) for the same period in the prior year. Energen Resources generated net income for the nine months ended September 30, 2010, of $174.7 million as compared with $161 million in the previous period primarily as a result of higher commodity prices (approximately $62 million after-tax) and increased production volumes (approximately $4 million). Negatively affecting net income was the impact of higher DD&A expense (approximately $10 million after-tax), increased production taxes (approximately $4 million after-tax), increased administrative expense (approximately $2 million after-tax), the $3.1 million after-tax gain on the 2009 sale of oil properties in the Permian Basin and increased exploration expense (approximately $33 million after-tax) largely due to the non-cash $24.6 million after-tax Alabama shale acreage write-off combined with the related $8.6 million write-off of well costs. Alagasco’s net income of $36.8 million in the current year- to- date compared to net income of $37.6 million in the same period in the previous 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 and the revised depreciation rates discussed above.

Oil and Gas Operations

Revenues from oil and gas operations rose 7.1 percent to $234.1 million for the three months ended September 30, 2010 largely as a result of increased natural gas and oil commodity prices partially offset by lower natural gas production volumes. For the year to date, revenues from oil and gas operations increased 16.5 percent to $706.3 million primarily as a result of increased natural gas and oil commodity prices along with the impact of higher oil production volumes partially offset by lower natural gas production volumes. During the current quarter, revenue per unit of production for natural gas rose 10.3 percent to $6.73 per thousand cubic feet (Mcf), while oil revenue per unit of production increased 19.9 percent to $76.80 per barrel. Natural gas liquids revenue per unit of production fell 11.4 percent to an average price of $0.78 per gallon. In the year- to- date, revenue per unit of production for natural gas increased 9.8 percent to $6.92 per Mcf, oil revenue per unit of production rose 31.9 percent to $78.09 per barrel and natural gas liquids revenue per unit of production fell 5.8 percent to an average price of $0.81 per gallon.

Production in the current quarter decreased largely due to drilling delays along with normal production declines. Year- to- date production rose primarily due to increased volumes related to the June 2009 purchase of certain Permian Basin oil properties partially offset by normal production declines and drilling delays. Natural gas production in the third quarter declined 6.1 percent to 17.7 billion cubic feet (Bcf), oil volumes increased 3 percent to 1,290 thousand barrels (MBbl) and natural gas liquids production decreased 1 percent to 19.8 million gallons (MMgal). For the year- to- date, natural gas production decreased 3.2 percent to 52.8 Bcf, while oil volumes rose 8 percent to 3,734 MBbl. Natural gas liquids production increased 3 percent to 57.6 MMgal. Natural gas comprised approximately 63 percent of Energen Resources’ production for the current quarter and the year- to- date.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. Energen Resources recorded no property sales in the third quarter of 2010. 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. Energen Resources recorded a pre-tax gain of $4.9 million in the third quarter of 2009 and a pre-tax gain of $5.2 in the year- to- date primarily from the sale of certain oil properties in the Permian Basin.

Operations and maintenance (O&M) expense increased $32.1 million for the quarter and $56.6 in the year- to- date. Lease operating expense (excluding production taxes) increased $1.9 million for the quarter largely due to higher ad valorem taxes (approximately $3.2 million) and increased marketing and transportation costs (approximately $0.7 million) partially offset by lower workover expense ($2.3 million). In the year- to- date, lease operating expense (excluding production taxes) increased $1.2 million primarily due to the June 2009 acquisition of Permian Basin oil

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properties (approximately $5.3 million), additional marketing and transportation costs ($2.2 million), higher ad valorem taxes (approximately $1.9 million) and increased electrical costs (approximately $1 million) partially offset by decreased workover expense ($5 million), lower nonoperated costs ($2.7 million) and decreased operation and maintenance expense ($1.1 million). Administrative expense decreased $3.2 million for the three months ended September 30, 2010 largely due to decreased legal expenses (approximately $2 million) and lower costs related to the Company’s performance-based compensation plans (approximately $0.9 million). For the nine months ended September 30, 2010, administrative expense rose $2.4 million primarily due to higher costs primarily related to the Company’s performance-based compensation plans (approximately $0.7 million) and increased insurance costs (approximately $0.4 million). Exploration expense rose $33.4 million in the third quarter of 2010 and $53 million year- to- date. 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 $2.9 million and increased $16.5 million year-to-date. The average depletion rate for the current quarter was $1.78 per thousand cubic feet equivalent (Mcfe) as compared to $1.63 per Mcfe in the same period a year ago. For the nine months ended September 30, 2010, the average depletion rate was $1.77 per Mcfe as compared to $1.58 per Mcfe in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $4.1 million and $12.9 million, respectively, to the increase in DD&A expense, was largely due to higher development costs along with the reserve revisions associated with lower year-end reserve pricing. Lower production volumes partially offset the increase to DD&A expense with an approximate $1.3 million for the three months ended September 30, 2010. Increased production volumes contributed approximately $3.3 million to the increase in DD&A expense for the nine months ended September 30, 2010.

Energen Resources’ expense for taxes other than income taxes was $1.4 million and $7 million higher in the three months and nine months ended September 30, 2010, respectively, largely due to production-related taxes. In the current quarter and year-to-date, higher oil, natural gas and natural gas liquid commodity market prices contributed approximately $1.7 million and $6.9 million, respectively, to the increase in production-related taxes. Decreasing production-related taxes were lower production volumes which contributed approximately $0.3 million for the quarter. In the year-to-date, higher production volumes contributed approximately $41,000 to increasing production-related taxes. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues decreased $7.1 million for the quarter largely due to a decline in gas costs partially offset by higher customer usage and adjustments from the utility’s rate setting mechanisms. During the third quarter of 2009, Alagasco had a $1.5 million pre-tax reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. For the current quarter, weather was comparable to the same quarter last year. Both residential sales volumes and commercial and industrial customer sales volumes fell 6.5 percent. Transportation volumes increased 2.7 percent in period comparisons. Revenues for the year-to-date rose $26.7 million primarily due to increased customer usage partially offset by a decrease in gas costs and adjustments for rate-setting purposes. In the current 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 that was 39 percent colder compared with the same period in the prior year contributed to a 24.6 percent increase in residential sales volumes and a 14.7 percent rise in commercial and industrial customer sales volumes due primarily to lower usage by large commercial and industrial customers during 2009. Transportation volumes increased 14.1 percent in period comparisons for the same reasons as described above. A decrease in gas costs partially offset by an increase in gas purchase volumes resulted in a 23.2 percent decrease in cost of gas for the quarter. For the year-to-date, a significant increase in gas purchase volumes partially offset by lower gas costs contributed to a 13.2 percent increase in cost of gas. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment mechanism that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

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O&M expense decreased 5.1 percent in the current quarter primarily due to decreased consulting and technology costs (approximately $1.1 million) and lower marketing expenses (approximately $0.5 million). In the nine months ended September 30, 2010, O&M expense fell 1.2 percent primarily due to decreased marketing expenses (approximately $1 million) and a decrease to bad debt expense (approximately $3.6 million) which included the 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. Partially offsetting these decreases were higher labor-related costs (approximately $2.3 million) and increased distribution operation expenses (approximately $1.1 million).

A 26.5 percent decrease in depreciation expense in the current quarter and a 9.8 percent decrease in the year-to-date was 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 $3.9 million and $5.3 million for the three months and nine months ended September 30, 2010, respectively. On June 28, 2010, the APSC approved a reduction in depreciation rates 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 in July, 2010 and will return to eligible customers an additional estimated $115.5 million, which includes approximately $23.1 million between December 1, 2010 and March 31, 2011. The remainder will be refunded to 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 Enhanced Stability Reserve (ESR) and other commission-approved charges. On November 1, 2010, the APSC specifically approved adjustments to the total amount refundable to include items originally approved in the APSC’s 1998 order establishing the ESR, environmental response costs and self insurance costs above $1 million per occurrence. The refund in July, 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 past five years. Approved depreciation rates averaged approximately 3.8 percent and 4.4 percent in the nine months ended September 30, 2010 and 2009, 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 decreased $0.4 million in the third quarter of 2010 and $0.2 million in the year-to-date. Income tax expense for the Company decreased $5.4 million in the current quarter largely due to lower pre-tax income. For the year-to-date, income tax expense rose $6.2 million primarily due to higher pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $517.9 million as compared to $531.6 million in the prior period. Net income increased during period comparisons primarily due to higher realized commodity prices along with increased production volumes at Energen Resources. The Company’s working capital needs were also influenced by accrued taxes along with commodity prices, and the timing of payments. During 2010, the income tax receivable increased approximately $48.3 million associated with the impact of bonus depreciation and the write-off of Alabama shale leasehold. Alagasco received a cash benefit in February 2009 from an approximate $26.2 million income tax refund claim from 2007 which resulted from an approved change by the Internal Revenue Service in a tax accounting method relating to the Company’s recovery of its gas distribution property. Working capital needs at Alagasco were additionally affected by decreased gas costs and storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $594.2 million for the nine months ended September 30, 2010 primarily due to additions of property, plant and equipment of $518.5 million and net short-term investments of $74.9 million. Energen Resources invested $443.8 million (includes approximately $5.3

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million of payments associated with accrued development cost) in capital expenditures primarily related to the acquisition and development of oil and gas properties. In September 2010, Energen Resources completed its purchase of oil properties located in the Permian Basin for a cash price of approximately $189 million. Utility capital expenditures totaled $74.7 million (excludes approximately $0.5 million of accrued capital cost) year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities.

The Company provided $14.6 million for net financing activities in the year-to-date primarily due to an increase in short-term borrowings partially offset by the payment of dividends to common shareholders.

Oil and Gas Operations

The Company anticipates continued price volatility due to supply- and- demand factors, weather, natural disasters, changes in global economics and political unrest. Commodity price volatility will affect the Company’s revenue and associated cash flow available for investment.

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2010, the Company expects its oil and gas capital spending to total approximately $586 million, including $353 million for existing properties, $209 million for acquisitions in the Permian and San Juan basins and $21 for exploration. On September 30, 2010, Energen completed the purchase of certain oil properties in the Permian Basin for a cash price of $189 million (subject to closing adjustments). This purchase had an effective date of September 1, 2010. Energen acquired proved reserves of approximately 18 million barrels of oil equivalents (MMBOE). Of the proved reserves acquired, an estimated 89 percent are undeveloped. The Company currently expects capital spending at Energen Resources to total approximately $510 million during 2011, including approximately $480 million for existing properties and $25 million for exploration. The 2011 projection may be revised as Energen Resources completes its formal budgeting process and incorporates the effect of any commodity price changes through year-end.

Not included in the above estimates for 2010 capital spending is the purchase and sale agreement Energen signed on October 29, 2010 to buy interests in certain oil properties in the Permian Basin for a cash purchase price of $75 million (subject to closing adjustments). This purchase is expected to close during the fourth quarter and will have an effective date of December 1, 2010. Energen will acquire total estimated 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 will use its credit facilities and internally generated cash flows to finance the acquisition.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions and additional development of existing properties. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions 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 primarily expects to use internally generated cash flow supplemented by its credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity. Energen Resources has $150 million of long-term debt due in December 2010.

Alabama Shales

In the third quarter of 2010, Energen Resources incurred a write-off of unproved capitalized leasehold associated with remainder of its Alabama shale leasehold. The non-cash charge totaled $14.6 million after-tax (approximately $0.20 per diluted share) and was charged to exploration expense after the Company determined that the flow rates were insufficient to support economic development. In the second quarter of 2010, Energen Resources recorded a non-cash write-off of approximately $10 million after-tax (approximately $0.14 per diluted share) of unproved leasehold costs associated with the deep Conasauga shale acreage. Efforts indicated that the acreage was not economically viable given associated capital costs and the outlook for natural gas prices.

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 in July, 2010 and will return to eligible customers an additional estimated $115.5 million, which includes approximately $23.1 million between December

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1, 2010 and March 31, 2011. The remainder will be refunded to 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. The refund in July, 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 past five years.

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 0.8 percent despite above-average levels of penetration along existing service lines. To increase its customer base, the utility is pursuing the acquisition of municipally owned gas systems in Alabama and capitalizing on opportunities to expand its service lines to areas with economic growth potential. 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.

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, generally warmer winters, 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 $34 million in 2010 but will vary depending upon the price of natural gas. During 2010 and 2011, Alagasco plans to invest an estimated $93 million and $75 million, respectively, in utility capital expenditures for normal distribution and support systems. The utility anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil 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. The Company’s current counterparties with active positions are Morgan Stanley Capital Group, Inc., J Aron & Company, Citibank, N.A., Bank of Montreal, Merrill Lynch Commodities, Inc., BP Corporation North America, Inc. (BP), Barclays Bank PLC, Wachovia Bank National Association and Shell Energy North America (US), L.P. At September 30, 2010, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with seven of its active counterparties and in a net loss position with the remaining two at September 30, 2010. 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 also 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 2010 and subsequent years:

Production     Period	Total Hedged Volumes	Average Contract Price		Description
Natural Gas
2010	3.5 Bcf		$8.79 Mcf		NYMEX Swaps
	9.4 Bcf		$7.23 Mcf		Basin Specific Swaps
2011	13.1 Bcf		$6.66 Mcf		NYMEX Swaps
	25.7 Bcf		$6.36 Mcf		Basin Specific Swaps
Oil
2010	973 MBbl		$86.65 Bbl		NYMEX Swaps
2011	3,729 MBbl		$77.26 Bbl		NYMEX Swaps
2011	* 518 MBbl		$86.45 Bbl		NYMEX Swaps
2012	3,337 MBbl		$81.63 Bbl		NYMEX Swaps
2012	* 244 MBbl		$88.80 Bbl		NYMEX Swaps
2013	1,608 MBbl		$81.43 Bbl		NYMEX Swaps
2013	* 1,454 MBbl		$89.02 Bbl		NYMEX Swaps
2014	1,176 MBbl		$84.14 Bbl		NYMEX Swaps
2014	* 720 MBbl		$90.68 Bbl		NYMEX Swaps
Oil Basis Differential
2010	574 MBbl		**		Basis Swaps
2011	2,076 MBbl		**		Basis Swaps
2012	672 MBbl		**		Basis Swaps
Natural Gas Liquids
2010	9.3 MMGal		$0.88 Gal		Liquids Swaps
2011	38.9 MMGal		$0.89 Gal		Liquids Swaps
2012	36.4 MMGal		$0.85 Gal		Liquids Swaps
*       Contract entered into subsequent to September 30, 2010 **    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 2010 and subsequent years:

Production     Period	Total Hedged Volumes	Description
2010	6.1 Bcf	NYMEX Swaps
2011	15.2 Bcf	NYMEX Swaps
2012	17.2 Bcf	NYMEX Swaps
2013	1.5 Bcf	NYMEX Swaps

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

See Note 4, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for information regarding the Company’s policies on fair value measurement.

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

	September 30, 2010
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	32,247		$	75,509		$	107,756
Noncurrent assets		(4,000	)		12,094			8,094
Current liabilities		(44,861	)		(160	)		(45,021	)
Noncurrent liabilities		(70,888	)		(566	)		(71,454	)
Net derivative asset (liability)	$	(87,502	)	$	86,877		$	(625	)

	December 31, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	57,235		$	62,208		$	119,443
Noncurrent assets		(1,600	)		9,424			7,824
Current liabilities		(25,518	)		(6,584	)		(32,102	)
Noncurrent liabilities		(59,914	)		(531	)		(60,445	)
Net derivative asset (liability)	$	(29,797	)	$	64,517		$	34,720

* 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, 2010, Alagasco had $41.9 million and $39.4 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, 2009, Alagasco has $25.8 million and $19 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, 2010 and December 31, 2009.

Level 3 assets and liabilities as of September 30, 2010 represent approximately 2 percent of total assets and an immaterial amount of total liabilities, respectively. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $20.4 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 qualifying 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, 2010. 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, 2010, the Company had noncash purchases of approximately $2.8 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

On October 29, 2010, Energen and Alagasco entered into an $850 million and a $150 million, respectively, three-year syndicated unsecured credit facility (credit facilities) with domestic and foreign lenders. These credit facilities replace the majority of the Company’s short-term credit facilities which were available to Energen and Alagasco. The Company has no amounts currently borrowed under these credit facilities. There are certain restrictive covenants including a financial covenant with a maximum consolidated debt to capitalization ratio of 65 percent. The Company currently has available credit facilities and short-term credit facilities as follows:

(in thousands)	Current Term		Energen		Alagasco		Total
Syndicated Credit Facility		10/29/2013	$	850,000	$	150,000	$	1,000,000
Bryant Bank		11/1/2011		-		9,000		9,000
BancorpSouth Bank		5/23/2011		-		10,000		10,000
Total			$	850,000	$	169,000	$	1,019,000

Energen and Alagasco rely upon excess cash flow supplemented by the 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. Energen Resources is a guarantor under the Energen credit facility.

Dividends

Energen expects to pay annual cash dividends of $0.52 per share on the Company’s common stock in 2010. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

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Contractual Cash Obligations 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, 2009.

Energen and its subsidiaries’ 2007 and 2008 federal consolidated income tax returns are currently 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. Although the timing of income tax audit resolutions is highly uncertain, an unfavorable outcome in this matter would result in income tax cash payments of approximately $31 million.

The Company has on-going income tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur within the next twelve months as a result of the completion of various audits and the expiration of statute of limitations. The change of the unrecognized tax benefits could have a material impact to the Company’s effective tax rate. The timing and outcome of these tax examinations is highly uncertain.

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 of federal oil and gas leases located 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 US federal leases. The Department proposes a change in the method of determining allowable deductions of transportation, fuel and processing costs from royalties due under the terms of the related leases. Such proposal, if determined appropriate, will result in increases of royalties due under the audit periods.

The Department’s preliminary findings are contrary to those allowed under previous audits and are inconsistent with the Company’s understanding of industry practice. The Company intends to vigorously contest the proposal under the preliminary findings and has requested additional information from the Department to determine the basis of its conclusion. Management is unable, at this time, to determine a range of reasonably possible losses as a result of this finding and no amount has been accrued as of September 30, 2010.

Recent Accounting Standards Updates

See Note 15, 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

Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company’s forward-looking statements do not reflect the impact of possible or pending acquisitions, investments, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any obligation to correct or update any forward-looking statements whether as a result of new information, future events or otherwise.

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, 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 uncertainties, all of which are difficult to predict.

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. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.

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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 have historically demonstrated that 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 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 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.

Alagasco’s Hedging:Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts 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 futures, swaps and fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position.

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. The three largest oil, natural gas and natural gas liquids purchasers are expected to account for approximately 21 percent, 17 percent and 13 percent, respectively, of Energen Resources’ estimated 2010 production. Energen Resources’ other purchasers are each expected to purchase less than 8 percent of estimated 2010 production.

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.

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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 Energen Resources’, Alagasco’s and the Company’s financial position, results of operations and cash flows.

Alagasco’s 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 September 30,						Nine months ended September 30,
(in thousands, except sales price data)	2010			2009			2010			2009
Oil and Gas Operations
Operating revenues
Natural gas	$	119,287		$	115,227		$	365,302		$	343,684
Oil		99,045			80,225			291,543			204,587
Natural gas liquids		15,388			17,496			46,535			48,212
Other		391			5,553			2,931			9,675
Total	$	234,111		$	218,501		$	706,311		$	606,158
Production volumes
Natural gas (MMcf)		17,723			18,881			52,768			54,532
Oil (MBbl)		1,290			1,253			3,734			3,456
Natural gas liquids (MMgal)		19.8			20.0			57.6			55.9
Total production volumes (MMcfe)		28,295			29,253			83,401			83,259
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	6.73		$	6.10		$	6.92		$	6.30
Oil (barrel)	$	76.80		$	64.03		$	78.09		$	59.19
Natural gas liquids (gallon)	$	0.78		$	0.88		$	0.81		$	0.86
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)	$	6.73		$	6.10		$	6.92		$	6.30
Oil (barrel)	$	76.80		$	63.71		$	78.09		$	58.95
Natural gas liquids (gallon)	$	0.78		$	0.88		$	0.81		$	0.86
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	4.03		$	3.06		$	4.40		$	3.34
Oil (barrel)	$	71.75		$	63.59		$	73.16		$	52.17
Natural gas liquids (gallon)	$	0.77		$	0.66		$	0.83		$	0.58
Other data
Lease operating expense (LOE)
LOE and other	$	47,405		$	45,480		$	135,965		$	134,723
Production taxes		10,475			9,050			31,062			24,160
Total	$	57,880		$	54,530		$	167,027		$	158,883
Depreciation, depletion and amortization	$	51,363		$	48,473		$	150,645		$	134,189
Capital expenditures	$	275,895		$	37,596		$	386,810		$	353,424
Exploration expenditures	$	34,506		$	1,120		$	54,367		$	1,374
Operating income	$	76,644		$	97,682		$	289,385		$	270,277
Natural Gas Distribution
Operating revenues
Residential	$	31,409		$	36,371		$	334,429		$	305,663
Commercial and industrial		17,130			20,834			128,216			126,128
Transportation		12,020			12,043			42,043			39,268
Other		1,134			(460	)		(6,556	)		398
Total	$	61,693		$	68,788		$	498,132		$	471,457
Gas delivery volumes (MMcf)
Residential		1,401			1,498			19,673			15,784
Commercial and industrial		1,155			1,235			8,735			7,613
Transportation		10,783			10,504			33,988			29,775
Total		13,339			13,237			62,396			53,172
Other data
Depreciation and amortization	$	9,451		$	12,850		$	34,380		$	38,119
Capital expenditures	$	38,283		$	21,133		$	75,810		$	57,107
Operating income (loss)	$	(9,015	)	$	(15,237	)	$	69,378		$	68,844

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges 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 natural gas and crude oil 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, 2010, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2014.

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 4, 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, 2010, was minimal as all long-term debt obligations were at fixed rates.

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ITEM 4. CONTROLS AND PROCEDURES

Energen Corporation
(a)	Our disclosure controls and procedures 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.

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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, 2010 through July 31, 2010		-			-		-		8,992,700
August 1, 2010 through August 31, 2010		-			-		-		8,992,700
September 1, 2010 through September 30, 2010		250	*	$	43.77		-		8,992,700
Total		250		$	43.77		-		8,992,700

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

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

ITEM 6. EXHIBITS

31(a)	–	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(b)	–	Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(c)	–	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(d)	–	Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
32(a)	–	Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)	–	Section 906 Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350
101	–	The following financial statements from Energen Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, 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, tagged as blocks of text.

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SIGNATURES

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

		ENERGEN CORPORATION ALABAMA GAS CORPORATION
November 4, 2010	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 4, 2010	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 4, 2010	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
November 4, 2010	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

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