Energen (EGN) 10-Q 2009 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2009

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. YESx 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 October 30, 2009.

Energen Corporation	$0.01 par value	71,753,041 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, 2009

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	25
	Selected Business Segment Data of Energen Corporation	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	37
Item 4.	Controls and Procedures	38
	PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
Item 6.	Exhibits	39
SIGNATURES		40

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)	2009			2008			2009			2008
Operating Revenues
Oil and gas operations	$	218,501		$	247,753		$	606,158		$	704,428
Natural gas distribution		68,788			82,452			471,457			488,689
Total operating revenues		287,289			330,205			1,077,615			1,193,117
Operating Expenses
Cost of gas		29,377			35,901			232,283			253,159
Operations and maintenance		97,963			88,168			274,850			268,147
Depreciation, depletion and amortization		61,323			47,111			172,308			133,641
Taxes, other than income taxes		15,471			27,266			57,099			92,039
Accretion expense		1,306			1,081			3,605			3,181
Total operating expenses		205,440			199,527			740,145			750,167
Operating Income		81,849			130,678			337,470			442,950
Other Income (Expense)
Interest expense		(10,017	)		(10,319	)		(29,586	)		(31,699	)
Other income		2,536			725			4,058			1,455
Other expense		(229	)		(2,009	)		(589	)		(3,057	)
Total other expense		(7,710	)		(11,603	)		(26,117	)		(33,301	)
Income Before Income Taxes		74,139			119,075			311,353			409,649
Income tax expense		27,018			46,011			113,649			153,019
Net Income	$	47,121		$	73,064		$	197,704		$	256,630
Diluted Earnings Per Average Common Share	$	0.65		$	1.01		$	2.75		$	3.56
Basic Earnings Per Average Common Share	$	0.66		$	1.02		$	2.76		$	3.58
Dividends Per Common Share	$	0.125		$	0.12		$	0.375		$	0.36
Diluted Average Common Shares Outstanding		71,996			72,116			71,878			72,129
Basic Average Common Shares Outstanding		71,651			71,590			71,641			71,604

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

3

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

(in thousands)	September 30, 2009		December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	14,853	$	13,177
Accounts receivable, net of allowance for doubtful accounts of $13,052 at September 30, 2009, and $12,868 at December 31, 2008		263,291		414,362
Inventories, at average cost
Storage gas inventory		61,307		77,243
Materials and supplies		20,087		13,541
Liquified natural gas in storage		3,096		3,219
Regulatory asset		42,580		41,714
Income tax receivable		3,654		50,476
Prepayments and other		13,137		29,309
Total current assets		422,005		643,041
Property, Plant and Equipment
Oil and gas properties, successful efforts method		3,308,876		2,959,665
Less accumulated depreciation, depletion and amortization		926,688		793,465
Oil and gas properties, net		2,382,188		2,166,200
Utility plant		1,192,381		1,166,967
Less accumulated depreciation		481,201		480,601
Utility plant, net		711,180		686,366
Other property, net		16,650		15,082
Total property, plant and equipment, net		3,110,018		2,867,648
Other Assets
Regulatory asset		102,841		97,511
Long-term derivative instruments		16,325		140,603
Deferred charges and other		33,605		26,601
Total other assets		152,771		264,715
TOTAL ASSETS	$	3,684,794	$	3,775,404

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, 2009			December 31, 2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Notes payable to banks	$	5,000		$	62,000
Accounts payable		107,266			224,309
Accrued taxes		47,462			42,183
Customers’ deposits		19,965			22,081
Amounts due customers		24,268			15,124
Accrued wages and benefits		19,095			24,966
Regulatory liability		7,778			25,363
Royalty payable		14,018			12,275
Deferred income taxes		26,462			41,969
Other		30,691			39,831
Total current liabilities		302,005			510,101
Long-term debt		560,996			561,631
Deferred Credits and Other Liabilities
Asset retirement obligation		77,598			66,151
Pension and other postretirement liabilities		62,889			67,474
Regulatory liability		153,151			147,514
Long-term derivative instruments		10,224			8,821
Deferred income taxes		512,095			482,058
Other		16,874			18,364
Total deferred credits and other liabilities		832,831			790,382
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, 74,577,060 shares issued at September 30, 2009, and 74,521,957 shares issued at December 31, 2008		746			745
Premium on capital stock		460,036			454,778
Capital surplus		2,802			2,802
Retained earnings		1,577,099			1,405,970
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges		102,161			200,867
Pension and postretirement plans		(32,762	)		(31,050	)
Deferred compensation plan		3,221			2,948
Treasury stock, at cost; 2,993,065 shares at September 30, 2009, and 2,977,947 shares at December 31, 2008		(124,341	)		(123,770	)
Total shareholders’ equity		1,988,962			1,913,290
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,684,794		$	3,775,404

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)	2009			2008
Operating Activities
Net income	$	197,704		$	256,630
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		172,308			133,641
Deferred income taxes		74,196			140,967
Change in derivative fair value		(913	)		(1,642	)
Gain on sale of assets		(5,392	)		(10,753	)
Other, net		(13,735	)		(2,018	)
Net change in:
Accounts receivable, net		97,965			42,640
Inventories		9,513			(12,899	)
Accounts payable		(61,026	)		(19,219	)
Amounts due customers		8,072			(16,140	)
Accrued taxes		52,109			(33,406	)
Other current assets and liabilities		788			(24,339	)
Net cash provided by operating activities		531,589			453,462
Investing Activities
Additions to property, plant and equipment		(266,674	)		(317,861	)
Acquisitions, net of cash acquired		(185,645	)		(16,099	)
Proceeds from sale of assets		7,426			16,216
Other, net		(1,450	)		(1,939	)
Net cash used in investing activities		(446,343	)		(319,683	)
Financing Activities
Payment of dividends on common stock		(26,575	)		(25,963	)
Issuance of common stock		464			208
Payment of long-term debt		(776	)		(10,676	)
Net change in short-term debt		(57,000	)		(111,000	)
Tax benefit on stock compensation		317			16,912
Net cash used in financing activities		(83,570	)		(130,519	)
Net change in cash and cash equivalents		1,676			3,260
Cash and cash equivalents at beginning of period		13,177			8,687
Cash and Cash Equivalents at End of Period	$	14,853		$	11,947

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)	2009			2008			2009			2008
Operating Revenues	$	68,788		$	82,452		$	471,457		$	488,689
Operating Expenses
Cost of gas		29,377			35,901			232,283			253,159
Operations and maintenance		35,579			33,642			99,871			99,076
Depreciation and amortization		12,850			12,262			38,119			36,401
Income taxes
Current		(12,475	)		(41,953	)		8,248			(21,445	)
Deferred		5,835			37,917			14,663			42,321
Taxes, other than income taxes		6,219			6,538			32,340			32,928
Total operating expenses		77,385			84,307			425,524			442,440
Operating Income (Loss)		(8,597	)		(1,855	)		45,933			46,249
Other Income (Expense)
Allowance for funds used during construction		370			189			920			515
Other income		1,040			170			1,594			539
Other expense		(178	)		(738	)		(521	)		(1,578	)
Total other income (expense)		1,232			(379	)		1,993			(524	)
Interest Charges
Interest on long-term debt		2,975			2,989			8,935			8,976
Other interest expense		406			581			1,359			1,972
Total interest charges		3,381			3,570			10,294			10,948
Net Income (Loss)	$	(10,746	)	$	(5,804	)	$	37,632		$	34,777

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

7

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

(in thousands)	September 30, 2009			December 31, 2008
ASSETS
Property, Plant and Equipment
Utility plant	$	1,192,381		$	1,166,967
Less accumulated depreciation		481,201			480,601
Utility plant, net		711,180			686,366
Other property, net		147			151
Current Assets
Cash and cash equivalents		8,420			9,728
Accounts receivable
Gas		55,852			146,886
Other		7,746			10,014
Allowance for doubtful accounts		(12,200	)		(12,100	)
Inventories, at average cost
Storage gas inventory		61,307			77,243
Materials and supplies		4,451			4,381
Liquified natural gas in storage		3,096			3,219
Deferred income taxes		24,014			22,152
Income tax receivable		3,417			30,654
Regulatory asset		42,580			41,714
Prepayments and other		4,621			2,622
Total current assets		203,304			336,513
Other Assets
Regulatory asset		102,841			97,511
Deferred charges and other		6,005			6,046
Total other assets		108,846			103,557
TOTAL ASSETS	$	1,023,477		$	1,126,587

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, 2009		December 31, 2008
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, 2009 and December 31, 2008		20		20
Premium on capital stock		31,682		31,682
Capital surplus		2,802		2,802
Retained earnings		284,485		273,743
Total common shareholder’s equity		318,989		308,247
Long-term debt		206,781		207,557
Total capitalization		525,770		515,804
Current Liabilities
Notes payable to banks		5,000		62,000
Accounts payable		57,027		110,838
Affiliated companies		12,216		21,582
Accrued taxes		33,639		33,911
Customers’ deposits		19,965		22,081
Amounts due customers		24,268		15,124
Accrued wages and benefits		8,136		10,497
Regulatory liability		7,778		25,363
Other		9,964		9,703
Total current liabilities		177,993		311,099
Deferred Credits and Other Liabilities
Deferred income taxes		119,098		102,473
Pension and other postretirement liabilities		26,005		30,021
Regulatory liability		153,151		147,514
Long-term derivative instruments		10,224		8,821
Other		11,236		10,855
Total deferred credits and other liabilities		319,714		299,684
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,023,477	$	1,126,587

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)	2009			2008
Operating Activities
Net income	$	37,632		$	34,777
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		38,119			36,401
Deferred income taxes		14,663			42,321
Other, net		(7,437	)		(2,037	)
Net change in:
Accounts receivable		74,239			49,978
Inventories		15,989			(15,921	)
Accounts payable		(52,313	)		(19,567	)
Amounts due customers		8,072			(16,140	)
Accrued taxes		26,973			(17,603	)
Other current assets and liabilities		(6,214	)		(5,778	)
Net cash provided by operating activities		149,723			86,431
Investing Activities
Additions to property, plant and equipment		(55,908	)		(44,365	)
Other, net		(1,091	)		(3,222	)
Net cash used in investing activities		(56,999	)		(47,587	)
Financing Activities
Dividends		(26,890	)		(25,793	)
Payment of long-term debt		(776	)		(676	)
Net advances (to) from affiliates		(9,366	)		26,038
Net change in short-term debt		(57,000	)		(39,000	)
Net cash used in financing activities		(94,032	)		(39,431	)
Net change in cash and cash equivalents		(1,308	)		(587	)
Cash and cash equivalents at beginning of period		9,728			7,335
Cash and Cash Equivalents at End of Period	$	8,420		$	6,748

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, 2008, 2007 and 2006 included in the 2008 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. The Company has evaluated subsequent events through November 3, 2009, which represents the date the consolidated condensed financial statements were issued.

2. REGULATORY MATTERS

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

Alagasco’s allowed range of return on average 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. 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. Alagasco did not have a reduction in rates related to the return on average equity for the rate year ended 2008. A $24.7 million and $12 million annual increase in revenues became effective December 1, 2008 and 2007, respectively.

At September 30, 2009, RSE limited the utility’s equity upon which a return is permitted to 55 percent, 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, 2008, the increase in O&M expense was below the Index Range; as a result the utility benefited by $2.9 million pre-tax with the related impact to rates effective December 1, 2008. Alagasco’s O&M expense fell within the Index Range for the rate year ended September 30, 2009.

11

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 that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

The APSC approved an Enhanced Stability Reserve (ESR) beginning October 1997, with an approved maximum funding level of $4 million pre-tax, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting fromforce majeure events such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco’s return on equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR in an amount of no more than $40,000 monthly until the maximum funding level is achieved. Under the terms of the current RSE extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR. Due to revenue losses from market sensitive large commercial and industrial customers, Alagasco utilized the ESR of approximately $4 million pre-tax during the third quarter of 2008. Alagasco is also allowed to utilize the ESR to recover certain environmental costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account, as more fully described in Note 9, Commitments and Contingencies.

3. DERIVATIVE COMMODITY INSTRUMENTS

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

Energen Resources periodically enters into derivative commodity instruments 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. The following counterparties, Morgan Stanley Capital Group, Inc., J Aron & Company, Merrill Lynch Commodities, Inc. and Citibank, N.A., represented approximately 31 percent, 22 percent, 22 percent and 19 percent, respectively, of Energen Resources’ net gain on fair value of derivatives. Energen Resources was in a net gain position with all of its counterparties at September 30, 2009.

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, 2009, 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 to hedge its exposure to price fluctuations 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

12

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 table details the fair values of commodity contracts by business segment on the balance sheets:

(in thousands)	September 30, 2009
	Oil and Gas Operations			Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable	$	171,056		$	-		$	171,056
Long-term derivative instruments		40,907			-			40,907
Total derivative assets		211,963			-			211,963
Accounts payable		(315	)		-			(315	)
Accounts receivable		(18,938	)*		-			(18,938	)
Long-term derivative instruments		(24,582	)*		-			(24,582	)
Total derivative liabilities		(43,835	)		-			(43,835	)
Total derivatives designated		168,128			-			168,128
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable		500			-			500
Long-term derivative instruments		-			-			-
Total derivative assets		500						500
Accounts payable		-			(25,939	)		(25,939	)
Long-term derivative instruments		-			(10,224	)		(10,224	)
Total derivative liabilities		-			(36,163	)		(36,163	)
Total derivatives not designated		500			(36,163	)		(35,663	)
Total derivatives	$	168,628		$	(36,163	)	$	132,465

* 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 $62.6 million and a net $123.1 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, 2009 and December 31, 2008, 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 on Income Statement	Three months ended September 30, 2009			Nine months ended September 30, 2009
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($24) million and $62.6 million	-	$	(39,132	)	$	102,161
Gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	61,114		$	200,672
Gain recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	754		$	262

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

(in thousands)	Location of Gain on Income Statement	Three months ended September 30, 2009		Nine months ended September 30, 2009
Gain recognized in income on derivative	Operating revenues	$	409	$	850

As of September 30, 2009, $92.2 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, 2009, the Company had 0.03 billion cubic feet (Bcf) of gas hedges and 118 thousand barrels (MBbl) of oil hedges which expire by year-end 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 2009 and subsequent years:

Production     Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2009	4.1 Bcf	$7.98 Mcf	NYMEX Swaps
	9.1 Bcf	$7.05 Mcf	Basin Specific Swaps
2010	14.9 Bcf	$8.68 Mcf	NYMEX Swaps
	29.4 Bcf	$7.88 Mcf	Basin Specific Swaps
2011	11.4 Bcf	$6.82 Mcf	NYMEX Swaps
	25.7 Bcf	$6.36 Mcf	Basin Specific Swaps
Oil
2009	1,030 MBbl	$71.11 Bbl	NYMEX Swaps
2010	3,465 MBbl	$86.75 Bbl	NYMEX Swaps
2011	3,012 MBbl	$75.67 Bbl	NYMEX Swaps
2012	852 MBbl	$71.30 Bbl	NYMEX Swaps
2013	336 MBbl	$73.30 Bbl	NYMEX Swaps
Oil Basis Differential
2009	754 MBbl	*	Basis Swaps
2010	2,383 MBbl	*	Basis Swaps
2011	2,076 MBbl	*	Basis Swaps
Natural Gas Liquids
2009	10.8 MMGal	$1.15 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 2009 and subsequent years:

Production     Period	Total Hedged Volumes	Description
2009	5.0 Bcf	NYMEX Swaps
2010	19.6 Bcf	NYMEX Swaps
2011	10.7 Bcf	NYMEX Swaps
2012	13.4 Bcf	NYMEX Swaps

As of September 30, 2009, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2013 and December 31, 2012, 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;

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

Level 3 – Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The fair value measure represents estimates of the assumptions that market value participants would use in pricing the asset or liability.

Over-the-counter derivatives are 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, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	76,238		$	76,380		$	152,618
Noncurrent assets		2,432			13,893			16,325
Current liabilities		(25,547	)		(707	)		(26,254	)
Noncurrent liabilities		(9,824	)		(400	)		(10,224	)
Net derivative asset	$	43,299		$	89,166		$	132,465

	December 31, 2008
(in thousands)	Level 2*			Level 3*		Total
Current assets	$	91,687		$	104,812	$	196,499
Noncurrent assets		91,321			49,282		140,603
Current liabilities		(27,653	)		-		(27,653	)
Noncurrent liabilities		(8,821	)		-		(8,821	)
Net derivative asset	$	146,534		$	154,094	$	300,628

* 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, 2009, Alagasco has $25.9 million and $10.2 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. As of December 31, 2008, Alagasco has $27.7 million and $8.8 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, 2009 and December 31, 2008.

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, 2009			Nine months ended September 30, 2009
Balance at beginning of period	$	144,883		$	154,094
Realized gains		(1,489	)		(1,489	)
Unrealized gains (losses) relating to instruments held at the reporting date		(14,166	)		60,245
Purchases and settlements during period		(40,062	)		(123,684	)
Balance at end of period	$	89,166		$	89,166

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(in thousands)	Three months ended September 30, 2008			Nine months ended September 30, 2008
Balance at beginning of period	$	(216,282	)	$	(9,998	)
Realized losses		13,375			29,119
Unrealized gains relating to instruments held at the reporting date		248,346			34,271
Purchases and settlements during period		-			(7,953	)
Balance at end of period	$	45,439		$	45,439

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

(in thousands, except per share amounts)	Three months ended September 30, 2009					Three months ended September 30, 2008
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	47,121	71,651	$	0.66	$	73,064	71,590	$	1.02
Effect of dilutive securities
Performance share awards			107					209
Stock options			188					227
Non-vested restricted stock			50					90
Diluted EPS	$	47,121	71,996	$	0.65	$	73,064	72,116	$	1.01

(in thousands, except per share amounts)	Nine months ended September 30, 2009				Nine months ended September 30, 2008
	Net Income	Shares	Per Share Amount		Net Income	Shares	Per Share Amount
Basic EPS	$197,704	71,641	$	2.76	$256,630	71,604	$	3.58
Effect of dilutive securities
Performance share awards		103				202
Stock options		88				234
Non-vested restricted stock		46				89
Diluted EPS	$197,704	71,878	$	2.75	$256,630	72,129	$	3.56

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, as their effect was non-dilutive. 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, as their effect were non-dilutive. For the three months and nine months ended September 30, 2008, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

5. SEGMENT INFORMATION

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

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	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2009			2008			2009			2008
Operating revenues
Oil and gas operations	$	218,501		$	247,753		$	606,158		$	704,428
Natural gas distribution		68,788			82,452			471,457			488,689
Total	$	287,289		$	330,205		$	1,077,615		$	1,193,117
Operating income (loss)
Oil and gas operations	$	97,682		$	137,270		$	270,277		$	377,852
Natural gas distribution		(15,237	)		(5,891	)		68,844			67,125
Eliminations and corporate expenses		(596	)		(701	)		(1,651	)		(2,027	)
Total	$	81,849		$	130,678		$	337,470		$	442,950
Other income (expense)
Oil and gas operations	$	(5,343	)	$	(7,672	)	$	(17,507	)	$	(21,834	)
Natural gas distribution		(2,149	)		(3,949	)		(8,301	)		(11,472	)
Eliminations and other		(218	)		18			(309	)		5
Total	$	(7,710	)	$	(11,603	)	$	(26,117	)	$	(33,301	)
Income before income taxes	$	74,139		$	119,075		$	311,353		$	409,649

(in thousands)	September 30, 2009		December 31, 2008
Identifiable assets
Oil and gas operations	$	2,657,751	$	2,650,136
Natural gas distribution		1,023,477		1,126,587
Subtotal		3,681,228		3,776,723
Eliminations and other		3,566		(1,319	)
Total	$	3,684,794	$	3,775,404

6. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended September 30,
(in thousands)	2009			2008
Net income	$	47,121		$	73,064
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($0.5) million and $232.3 million		(774	)		379,007
Reclassification adjustment for derivative instruments, net of tax of ($23.5) million and $22.9 million		(38,358	)		37,333
Pension and postretirement plans, net of tax of ($1.5) million and ($0.9) million		(2,729	)		(1,710	)
Comprehensive income	$	5,260		$	487,694

	Nine months ended September 30,
(in thousands)	2009			2008
Net income	$	197,704		$	256,630
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $15.9 million and ($39.4) million		25,872			(64,256	)
Reclassification adjustment for derivative instruments, net of tax of ($76.4) million and $60.6 million		(124,578	)		98,902
Pension and postretirement plans, net of tax of ($0.9) million and ($0.4) million		(1,712	)		(680	)
Comprehensive income	$	97,286		$	290,596

(in thousands)	September 30, 2009			December 31, 2008
Unrealized gain on hedges, net of tax of $62.6 million and $123.1 million	$	102,161		$	200,867
Pension and postretirement plans, net of tax of ($17.6) million and ($16.7) million		(32,762	)		(31,050	)
Accumulated other comprehensive income	$	69,399		$	169,817

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7. STOCK COMPENSATION

1997 Stock Incentive Plan

The 1997 Stock Incentive Plan provided 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 538,492 non-qualified option shares during the first quarter of 2009 with a grant-date fair value of $8.83. In August 2009, the Company granted 4,750 non-qualified option shares with grant-date fair value of $15.00.

Additionally, the 1997 Stock Incentive Plan provided for the grant of restricted stock. In August 2009, 6,150 shares of restricted stock were awarded. These awards were valued based on the quoted market price of the Company’s common stock at the date of grant and have a three year vesting period.

2004 Stock Appreciation Rights Plan

The Energen 2004 Stock Appreciation Rights Plan provided 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 305,257 and 3,292 awards during the first quarter of 2009. These awards had fair values of $19.98 and $19.28, respectively, as of September 30, 2009.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provided 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. In the first quarter of 2009, Energen Resources awarded 900 Petrotech units with a two year vesting period and 2,911 Petrotech units with a three year vesting period. These awards had a fair value of $42.48 and $42, respectively, as of September 30, 2009. During the third quarter of 2009, Energen Resources awarded 938 Petrotech units with a three year vesting period and a fair value of $42 as of September 30, 2009.

1997 Deferred Compensation Plan

During the nine months ended September 30, 2009, the Company had noncash purchases of approximately $0.6 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

8. EMPLOYEE BENEFIT PLANS

As of December 31, 2008, the Company measures the funded status of its employee benefit plans as of the date of its year-end statement of financial position. Previously, the Company used a September 30 valuation date for its benefit plans. During the fourth quarter of 2008, the Company changed the measurement date to December 31 using the alternative method. The Company recognized a one-time reduction to retained earnings of $1.8 million pre-tax and an increase to the current and noncurrent regulatory assets of Alagasco totaling approximately $0.1 million and $1.4 million pre-tax, respectively. The increase to regulatory assets which total $1.5 million will be recovered in rates over the average remaining service lives of each plan.

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)	2009			2008			2009			2008
Components of net periodic benefit cost:
Service cost	$	1,835		$	1,790		$	5,505		$	5,370
Interest cost		3,016			2,950			9,048			8,851
Expected long-term return on assets		(3,501	)		(3,289	)		(10,502	)		(9,867	)
Actuarial loss		997			1,071			2,991			3,212
Prior service cost amortization		145			230			434			689
Termination benefit charge		-			-			145			-
Net periodic expense	$	2,492		$	2,752		$	7,621		$	8,255

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In September 2009, the Company made discretionary contributions of $15 million to the assets of a defined benefit qualified pension plan. The Company is not required to make any additional contributions during 2009. For the three months and nine months ended September 30, 2009, the Company made benefit payments aggregating $0.2 million and $3.8 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 2009. In the second quarter of 2009, the Company recognized a termination benefit charge of $145,000 to provide for early retirement of certain non-highly compensated employees.

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)	2009			2008			2009			2008
Components of net periodic benefit cost:
Service cost	$	453		$	409		$	1,360		$	1,228
Interest cost		1,212			1,229			3,637			3,685
Expected long-term return on assets		(885	)		(1,384	)		(2,657	)		(4,150	)
Actuarial loss (gain)		57			(195	)		171			(586	)
Transition amortization		479			479			1,438			1,438
Net periodic expense	$	1,316		$	538		$	3,949		$	1,615

For the three months and nine months ended September 30, 2009, the Company made contributions aggregating $1.3 million and $3.9 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $1.3 million to postretirement benefit plan assets through the remainder of 2009.

9. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Certain of Alagasco’s long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $131 million through September 2024. 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 98 Bcf through April 2015.

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, 2009, the fixed price purchases under these guarantees had a maximum term outstanding through September 2010 and an aggregate purchase price of $7.3 million with a market value of $7.4 million.

Legal Matters:Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business

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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. While Alagasco no longer owns the Huntsville site, the Company and the current site owner have agreed to enter into a Consent Order and 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 $3.8 million to $7.8 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, 2009, the Company incurred costs of $36,000 and $120,000 associated with the site. As of September 30, 2009, the Company has accrued a contingent liability of $3.7 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 insurance recovery and future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

10. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, 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, with a carrying value of $561,781,000 approximates $578,946,000 at September 30, 2009. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, with a carrying value of $206,781,000 approximates $206,166,000 at September 30, 2009. The fair values were based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating.

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11. REGULATORY ASSETS AND LIABILITIES

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

	September 30, 2009				December 31, 2008
(in thousands)	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	132	$	74,527	$	132	$	72,560
Accretion and depreciation for asset retirement obligation		-		14,087		-		13,145
Gas supply adjustment		16,186		-		11,173		-
Risk management activities		25,939		10,224		27,653		8,821
RSE adjustment		93		-		2,688		-
Enhanced stability reserve		-		3,814		-		2,917
Other		230		189		68		68
Total regulatory assets	$	42,580	$	102,841	$	41,714	$	97,511
Regulatory liabilities:
RSE adjustment	$	1,645	$	-	$	137	$	-
Unbilled service margin		6,100		-		25,192		-
Asset removal costs, net		-		134,496		-		129,579
Asset retirement obligation		-		17,777		-		17,024
Other		33		878		34		911
Total regulatory liabilities	$	7,778	$	153,151	$	25,363	$	147,514

12. ASSET RETIREMENT OBLIGATIONS

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

During the nine months ended September 30, 2009, 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, 2008	$	66,151
Liabilities incurred		8,226
Liabilities settled		(384	)
Accretion expense		3,605
Balance of ARO as of September 30, 2009	$	77,598

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 $17.8 million and $17 million to purge and cap its gas pipelines upon abandonment as a regulatory liability as of September 30, 2009 and December 31, 2008, 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. The accumulated asset removal costs of $134.5 million and $129.6 million for September 30, 2009 and December 31, 2008, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets.

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13. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

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 Corporation (Range Resources) for a cash price of $182 million (subject to closing adjustments). This sale has an effective date of May 1, 2009. Energen acquired proved reserves of approximately 15.2 million barrels of oil equivalents. 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 acquisition qualifies as a business combination, and as such, the Company estimated the fair value of this property as of the June 30, 2009 acquisition date, the date on which the acquirer obtained control of the acquiree. The 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). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs.

The Company estimates the fair value of these properties to be approximately $186.6 million, which the Company concludes approximates the fair value that would be paid by a typical market participant. This measurement resulted in no goodwill being recognized. The acquisition related costs have been expensed as incurred in operations and maintenance expense on the consolidated income statement.

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. The purchase price allocation is preliminary and subject to adjustment as the final closing statement will be complete during the fourth quarter of 2009.

(in thousands)
Consideration given to Range Resources
Cash (net)	$	181,198
Recognized amounts of identifiable assets acquired and liabilities assumed
Proved developed properties	$	182,762
Unproved leasehold properties		3,800
Accounts receivable		4,919
Inventory and other		455
Asset retirement obligation		(6,590	)
Environmental liabilities		(3,124	)
Accounts payable		(1,024	)
Total identifiable net assets	$	181,198

Summarized below are the consolidated results of operations for the three months and nine months ended September 30, 2009 and 2008, on an unaudited pro forma basis as if the acquisition had occurred at the beginning of each of the periods presented. The pro forma information is based on the Company’s consolidated results of operations for the three months and nine months ended September 30, 2009 and 2008, 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.

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	Three months ended September 30,				Nine months ended September 30,
(in thousands)	2009		2008		2009		2008
Operating revenues	$	287,289	$	358,872	$	1,096,190	$	1,271,298
Operating income	$	81,849	$	150,153	$	341,701	$	493,983

During the nine months ended September 30, 2009, Energen Resources capitalized approximately $4.3 million of unproved leaseholds costs, approximately $0.1 million of which was related to the Company’s acreage position in Alabama shales. Energen used its available cash and existing lines of credit to finance these unproved leasehold costs.

Energen Resources recorded a $10.3 million pre-tax gain in other operating revenues from the March 2008 property sale of certain Permian Basin oil properties. The Company received approximately $15.5 million pre-tax in cash from the sale of this property.

14. RECENTLY ISSUED ACCOUNTING STANDARDS

As of January 1, 2008, the Company adopted new accounting guidance on fair value measurements for financial assets and liabilities. This new guidance defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. As of January 1, 2009, the Company adopted the guidance related to non-financial assets and liabilities with no impact to the Company’s consolidated financial statements or the results of operations.

On January 1, 2009, the Company adopted new accounting guidance which establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the noncontrolling interest, changes in a parent’s ownership interest, and the valuation of retained noncontrolling equity investments when a subsidiary is deconsolidated. This standard also establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This standard did not have an effect on the consolidated financial statements or the results of operations of the Company.

On January 1, 2009, the Company adopted revised accounting guidance for business combinations, which was issued to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. Under this guidance, a company is required to recognize the assets acquired, liabilities assumed, contractual contingencies, and any contingent consideration measured at their fair value at the acquisition date. This guidance has been applied to an acquisition made during the second quarter of 2009 (see Note 13, Acquisition and Dispositions of Oil and Gas Properties).

On January 1, 2009, the Company adopted new accounting guidance expanding quarterly disclosure requirements about an entity’s derivative instruments and hedging activities. The additional disclosures for derivative instruments are included in Note 3, Derivative Commodity Instruments.

On January 1, 2009, the Company adopted a newly issued accounting standard which addresses whether instruments granted in share-based payment transactions are participating securities. This accounting standard requires us to include all unvested stock awards which contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, in the number of shares outstanding in our basic and diluted EPS calculations. This standard did not have a material impact on the consolidated financial statements or the results of operations of the Company.

On June 30, 2009, the Company adopted accounting guidance which requires disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements. The implementation of this accounting guidance did not have a material impact on the consolidated financial statements or the results of operations.

On June 30, 2009, the Company adopted a new accounting standard which provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased. This guidance did not have an effect on the consolidated financial statements or the results of operations of the Company.

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On June 30, 2009, the Company adopted an accounting standard which establishes principles and requirements for subsequent events. The additional disclosure for subsequent events is included in Note 1, Commitments and Contingencies.

In June 2009, the FASB issued 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 guidance is effective for fiscal years beginning after November 15, 2009. The Company is currently evaluating the impact of the standard.

In December 2008, the FASB issued new accounting guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. This guidance requires additional disclosures to aid in the understanding of: (1) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies, (2) the major categories of plan assets, (3) the inputs and valuation techniques used to measure the fair value of plan assets, (4) the effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period, and (5) significant concentrations of risk within plan assets. This guidance is effective for fiscal years ending after December 15, 2009 and is not expected to have a material impact on the consolidated financial statements or the results of operations.

On December 31, 2008, the Securities and Exchange Commission (SEC) issued its final rule Modernization of Oil and Gas Reporting (Final Rule), which revises the disclosures required by oil and gas companies. In addition to changing the definition and disclosure requirements for oil and gas reserves, the Final Rule changes the requirements for determining quantities of oil and gas reserves. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves, with a view to helping investors evaluate their investments in oil and gas companies. The amendments are designed to modernize the requirements for the determination of oil and gas reserves, aligning them with current practices and updating them for changes in technology. The Final Rule applies to annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009, pending the potential alignment of certain accounting standards by the FASB with the Final Rule. The Company is currently studying the impact of the Final Rule.

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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 $47.1 million ($0.65 per diluted share) for the three months ended September 30, 2009 compared with net income of $73.1 million ($1.01 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, 2009, of $59 million as compared with $79.6 million in the same quarter in the previous year. Significantly lower commodity prices (approximately $40 million after-tax), increased depreciation, depletion and amortization (DD&A) expense (approximately $8 million after-tax) and increased administrative expense (approximately $4 million after-tax) were partially offset by increased natural gas, oil and natural gas liquids production volumes (approximately $20 million after-tax), lower production taxes (approximately $7 million after-tax) and an after-tax gain of $3.1 million on the sale of certain oil properties in the Permian Basin. Energen’s natural gas utility, Alagasco, reported a net loss of $10.7 million in the third quarter of 2009 compared to a net loss of $5.8 million in the same period last year largely due to the prior quarter utilization of the Enhanced Stability Reserve (ESR) to compensate for certain large industrial and commercial load loss (approximately $2.5 million after tax), the benefit in the third quarter of 2008 from the increase in O&M expense being below its inflation-based cost control measure (approximately $1.8 million after-tax) and timing differences associated with rate recovery under other Alagasco rate mechanisms combined with the utility’s ability to earn on a higher level of equity (approximately $1.1 million after-tax).

For the 2009 year-to-date, Energen’s net income totaled $197.7 million ($2.75 per diluted share) and compared to net income of $256.6 million ($3.56 per diluted share) for the same period in the prior year. Energen Resources generated net income for the nine months ended September 30, 2009, of $161 million as compared with $222.6 million in the previous period primarily as a result of lower commodity prices (approximately $103 million after-tax), higher DD&A expense (approximately $23 million after-tax), a 2008 after-tax gain of $6.4 million on the sale of certain Permian Basin oil properties and increased lease operating expenses (approximately $4 million after-tax). Positively affecting net income was the impact of increased production volumes (approximately $46 million after-tax), decreased production taxes (approximately $22 million after-tax) and the $3.1 million after-tax gain on the sale of oil properties in the Permian Basin. Alagasco’s net income of $37.6 million in the current year-to-date compared to net income of $34.8 million, largely reflecting the utility’s ability to earn on a higher level of equity combined with timing differences associated with rate recovery (approximately $2.8 million after-tax) and increased revenue from cycle sales partially offset by decreased revenue from large commercial and industrial customers. Negatively affecting net income, as discussed above, was the prior year charge against the ESR (approximately $2.5 million after-tax) and the prior year benefit from the increase in O&M expense being below its inflation-based cost control measure (approximately $1.8 million after-tax).

Oil and Gas Operations

Revenues from oil and gas operations declined 11.8 percent to $218.5 million for the three months ended September 30, 2009 and 14 percent to $606.2 million in the year-to-date largely as a result of decreased commodity prices partially offset by the impact of higher production volumes. During the current quarter, revenue per unit of production for natural gas fell 27.6 percent to $6.10 per thousand cubic feet (Mcf), while oil revenue per unit of production decreased 18 percent to $64.03 per barrel. Natural gas liquids revenue per unit of production decreased 14.6 percent to an average price of $0.88 per gallon. In the year-to-date, revenue per unit of production for natural gas declined 23.4 percent to $6.30 per Mcf, oil revenue per unit of production decreased 19.7 percent to $59.19 per barrel and natural gas liquids revenue per unit of production fell 18.9 percent to an average price of $0.86 per gallon.

Production for both the current quarter and year-to-date increased primarily due to additional development activities in the San Juan and Permian basins and increased volumes related to the June 2009 purchase of Permian Basin oil properties, acquiring proved reserves of approximately 15.2 million barrels of oil equivalents, partially offset by normal production declines. Natural gas production in the third quarter rose 9.4 percent to 18.9 billion cubic feet (Bcf), oil volumes increased 18.8 percent to 1,253 thousand barrels (MBbl) and natural gas liquids production increased 12.4 percent to 20 million gallons (MMgal). For the year-to-date, natural gas production increased 8.9 percent to 54.5 Bcf, while oil volumes rose 15 percent to 3,456 MBbl. Natural gas liquids production increased 6.1 percent to 55.9 MMgal. Natural gas comprised approximately 65 percent of Energen Resources’ production for the current quarter and the year-to-date.

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Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. Energen Resources recorded 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. In the third quarter of 2008, Energen Resources recorded a pre-tax gain of $0.1 million and a pre-tax gain of $10.3 million in the year-to-date largely from the sale of certain Permian Basin oil properties.

O&M expense increased $8 million for the quarter and $6.3 million in the year-to-date. Lease operating expense (excluding production taxes) increased by $1.6 million for the quarter largely due to the June 2009 acquisition of Permian Basin oil properties (approximately $3.3 million) partially offset by lower ad valorem taxes (approximately $2 million). In the year-to-date, lease operating expense (excluding production taxes) rose $6.1 million primarily due to the oil property acquisition (approximately $3.3 million), increased ad valorem taxes (approximately $1.4 million), higher labor costs (approximately $1.2 million) and increased marketing and transportation costs (approximately $1.1 million) partially offset by decreased electrical costs (approximately $1 million). Administrative expense increased $6.2 million for the three months ended September 30, 2009 largely due to higher benefit costs primarily related to the Company’s performance-based compensation plans (approximately $3.5 million) and increased litigation reserves (approximately $1.7 million). For the nine months ended September 30, 2009, administrative expense rose $3 million largely due to increased benefit costs (approximately $2.6 million) and litigation reserve increases (approximately $1.1 million) as described above partially offset by insurance recoveries associated with certain legal expenses (approximately $0.9 million). Exploration expense rose $0.2 million in the third quarter of 2009. In the year-to-date, exploration expense declined $2.8 million primarily due to mechanical difficulties encountered in the prior year while drilling an exploratory well in the San Juan Basin.

Energen Resources’ DD&A expense for the quarter rose $13.6 million and increased $36.9 million year-to-date. The average depletion rate for the current quarter was $1.63 per thousand cubic feet equivalent (Mcfe) as compared to $1.30 per Mcfe in the same period a year ago. For the nine months ended September 30, 2009, the average depletion rate was $1.58 per Mcfe as compared to $1.25 per Mcfe in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $11 million and $26.7 million, respectively, was largely due to increased development costs and the negative effect on reserves of lower year-end oil and gas prices. Increased production volumes also contributed approximately $2.6 million and $10.2 million to the increase in DD&A expense in the three months and nine months ended September 30, 2009, respectively.

Energen Resources’ expense for taxes other than income taxes was $11.5 million and $34.4 million lower in the three months and nine months ended September 30, 2009, respectively, largely due to production-related taxes. In the current quarter and year-to-date, lower oil, natural gas and natural gas liquid commodity market prices contributed approximately $14 million and $40.5 million, respectively, to the decrease in production-related taxes. Partially offsetting the decreases in production-related taxes were higher production volumes which contributed approximately $2.5 million and $5.9 million, respectively, for the quarter and year-to-date. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues declined $13.7 million for the quarter largely related to adjustments from the utility’s rate setting mechanisms along with a decline in gas costs and a decrease in customer usage. In the current quarter, 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. Alagasco charged approximately $4 million against the ESR during the third quarter of 2008 due to a decline in usage by certain market sensitive large commercial and industrial customers. At the end of the 2008 rate year, the increase in O&M expense was below its inflation-based cost control measure; as a result the utility benefited by a $2.9 million pre-tax increase in revenues for the three months ended September 30, 2008. For the third quarter, weather was comparable with the same quarter in the prior year. Residential sales volumes decreased slightly, commercial and industrial customer sales volumes declined 11.2 percent and transportation volumes fell 1.9 percent in period comparisons. Revenues for the year-to-date declined $17.2 million primarily due to the adjustments for rate-setting purposes described above, decreased customer usage and lower gas

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costs. For the year-to-date, weather was 5 percent warmer compared to the same period last year. Residential sales volumes declined 2.8 percent, while commercial and industrial customer sales volumes decreased 8.8 percent. Transportation volumes declined 17.9 percent in period comparisons due primarily to decreased large customer and industrial usage. A decrease in gas costs along with lower gas purchase volumes resulted in an 18.2 percent decrease in cost of gas for the quarter and an 8.2 percent decrease of the year-to-date. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment mechanism that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

O&M expense rose 5.8 percent in the current quarter primarily due to increased marketing expenses (approximately $2 million) and increased labor-related costs (approximately $0.9 million), partially offset by decreased insurance costs (approximately $2.2 million). In the nine months ended September 30, 2009, O&M expense increased 1 percent. Higher marketing expenses (approximately $2.5 million) were largely offset by lower distribution operation expenses (approximately $1.6 million) and decreased insurance costs (approximately $0.5 million).

A 4.8 percent increase in depreciation expense in the current quarter and a 4.7 percent increase in the year-to-date was primarily due to extension and replacement of the utility’s distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company decreased $0.3 million in the third quarter of 2009 primarily due to lower interest rates on short-term borrowings partially offset by an increase in short-term borrowings related to the June 2009 purchase of Permian Basin oil properties at Energen Resources. In the year-to-date, interest expense fell $2.1 million largely due to lower borrowings at Energen Resources combined with lower interest rates on short-term borrowings. Income tax expense for the Company decreased $19 million in the current quarter and $39.4 million year-to-date largely due to lower pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $531.6 million as compared to $453.5 million in the prior period. Net income decreased during period comparisons primarily due to lower realized commodity prices partially offset by higher production volumes at Energen Resources and lower production taxes. These decreases were more than offset by lower working capital requirements which were influenced primarily by accrued taxes along with commodity prices and the timing of payments. Working capital needs at Alagasco were additionally affected by decreased storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $446.3 million for the nine months ended September 30, 2009 primarily due to additions of property, plant and equipment. Energen Resources invested $397.4 million (includes approximately $55.8 million of payments associated with accrued development cost) in capital expenditures primarily related to the acquisition and development of oil and gas properties. In June 2009, Energen Resources completed its purchase of oil properties located in the Permian Basin for a cash price of approximately $182 million. The acquisition added approximately 15.2 million barrels of oil equivalents in proved reserves. During the year-to-date, Energen Resources received cash proceeds of $7.4 million primarily from the sale of certain Permian Basin oil properties. Utility capital expenditures totaled $55.9 million (excludes approximately $0.2 million of accrued capital cost) in the year-to-date and primarily represented expansion and replacement of its distribution system and support facilities, including the implementation of the Customer Care and Service (CCS) software system.

The Company used $83.6 million for net financing activities in the year-to-date primarily due to the decrease in short-term debt borrowings and the payment of dividends to common shareholders.

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Recent Market Events

Capital and credit markets have experienced significant volatility and disruption since 2008. If such economic disruptions were to worsen, the Company could experience material adverse effects upon its financial position, results of operations and cash flows. These events have the potential for negative impact including, but not limited to, the following areas:

Risk Management: The Company utilizes derivative instruments to hedge its exposure to commodity price fluctuations. These derivative instruments are entered into with investment grade counterparties and are assessed each reporting period as to hedge effectiveness. Specifically, the Company considers the likelihood that the counterparty will be able to perform under the terms of the derivative instrument. If the Company is unable to conclude that it is probable that such counterparty will be able to perform under the terms of the derivative instrument, then the Company would be required to cease hedge accounting and recognize all gains and losses from that point forward in its results of operations. Further, the Company is at risk of nonperformance for any derivative contracts which are in a gain position. 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, Barclays Bank PLC, Wachovia Bank National Association and Shell Energy North America (US), L.P.

Access to Capital: Energen and Alagasco rely upon excess cash flows supplemented by short-term credit facilities to fund working capital needs. The Company currently has available short-term credit facilities with nine financial institutions aggregating $525 million of which Energen has available $230 million, Alagasco has available $110 million and $185 million is available to either company. These short-term credit facilities are 364-day committed bilateral agreements. Energen and Alagasco are subject to the risk that these facilities will not be renewed or will be renewed at less favorable terms. However, the Company believes that its expected cash flows, the diversity of credit facilities and its ability to adjust future capital spending provides adequate support for its liquidity needs.

Oil and Gas Operations

During 2009, Energen Resources anticipates some decline in various market driven costs due to the recently lower commodity price environment including, but not limited to, workover and maintenance expenses, capital costs and other field-service-related expenses. The Company anticipates influences such as supply-and-demand factors, weather, natural disasters, changes in global economics and political uncertainty will continue to contribute to price volatility. 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 2009, the Company expects its oil and gas capital spending to total approximately $450 million, including $247 million for existing properties and $187 for property acquisitions. In June 2009 the Company purchased certain oil properties for a cash price of $182 million (subject to closing adjustments) in the Permian Basin from Range Resources Corporation (Range Resources). The effective date of this acquisition was May 1, 2009. Energen Resources used its short-term credit facilities and internally generated cash flows to finance the acquisition. The Company anticipates development costs of approximately $11.9 million during 2009 for this acquisition. The Company currently expects capital spending at Energen Resources to total approximately $310 million during 2010, including approximately $290 million for existing properties. The 2010 projection may be revised as Energen Resources completes its formal budgeting process and incorporates the effect of any commodity price changes through year-end.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional development of existing properties and the exploration and further development of potential shales acreage primarily in Alabama. 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 further property acquisitions is subject to market conditions and industry trends. Property acquisitions, other than Range Resources discussed above, are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company primarily expects to use internally generated cash flow supplemented by its short-term 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.

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Alabama Shales

In October 2006, Energen Resources sold to Chesapeake Energy Corporation (Chesapeake) a 50 percent interest in its unproved lease position of approximately 200,000 gross acres in various shale plays in Alabama for $75 million plus certain net drilling cost (approximately $10.85 million). Currently, Energen Resources’ net acreage position in Alabama shales totals approximately 330,000 acres representing multiple shale opportunities. As of September 30, 2009, Energen Resources had approximately $41 million of unproved leasehold costs related to its lease position in Alabama shales.

Effective April 1, 2009, Chesapeake agreed to farm out its half-interest in Alabama shales to Energen Resources. Under this agreement, Energen Resources has 18 months to drill two wells; after each well is drilled, Chesapeake will farm out its 50 percent interest to Energen Resources. Chesapeake will retain a net overriding royalty interest of approximately 1 to 2.5 percent convertible to a proportionately reduced working interest of 25 percent (net 12.5 percent) at 125 percent payout on a well-by-well basis.

Energen Resources expects results upon completion of its Chattanooga shale well during the fourth quarter of 2009. The costs related to this well are estimated to be approximately $4 million. Approximately $15 million of the $41 million of unproved leasehold costs for Alabama shales mentioned above are associated with the Chattanooga shale formation. In the event this well is unsuccessful and the Company concludes no further activity is warranted, Energen Resources would expect to record a loss associated with well costs and the non-cash write-off on capitalized unproved leasehold.

Natural Gas Distribution

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) and is allowed to earn a range of return on equity of 13.15 percent to 13.65 percent. At September 30, 2009, RSE limited 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.

In recent years, the higher price commodity and reduced economic environment has contributed to the decline in the utility’s customer base and in declines in usage volume per customer. A return of natural gas prices to higher levels could result in a further decline in Alagasco’s customer base and usage and in increases in the utility’s GSA. During 2008, Alagasco charged approximately $4 million against the ESR due to a decline in usage by its construction industry related customers. Alagasco expects this lower level of usage to continue in the near term. Alagasco will continue to monitor its bad debt reserve and will make adjustments as required based on the evaluation of its receivables which are materially impacted by natural gas prices and the underlying current and future economic conditions facing the utility’s customer base.

Alagasco maintains an investment in storage gas that is expected to average approximately $55 million in 2009 but will vary depending upon the price of natural gas. During 2009 and 2010, Alagasco plans to invest an estimated $75 million and $80 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 short- term credit facilities. 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.

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 banks and energy-trading firms. At September 30, 2009, 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 all of its counterparties at September 30, 2009. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. These hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

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Alagasco also enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or liability.

Energen Resources entered into the following transactions for the remainder of 2009 and subsequent years:

Production     Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2009	4.1 Bcf	$7.98 Mcf	NYMEX Swaps
	9.1 Bcf	$7.05 Mcf	Basin Specific Swaps
2010	14.9 Bcf	$8.68 Mcf	NYMEX Swaps
	29.4 Bcf	$7.88 Mcf	Basin Specific Swaps
2011	11.4 Bcf	$6.82 Mcf	NYMEX Swaps
	25.7 Bcf	$6.36 Mcf	Basin Specific Swaps
Oil
2009	1,030 MBbl	$71.11 Bbl	NYMEX Swaps
2010	3,465 MBbl	$86.75 Bbl	NYMEX Swaps
2011	3,012 MBbl	$75.67 Bbl	NYMEX Swaps
2012	852 MBbl	$71.30 Bbl	NYMEX Swaps
2013	336 MBbl	$73.30 Bbl	NYMEX Swaps
Oil Basis Differential
2009	754 MBbl	*	Basis Swaps
2010	2,383 MBbl	*	Basis Swaps
2011	2,076 MBbl	*	Basis Swaps
Natural Gas Liquids
2009	10.8 MMGal	$1.15 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 2009 and subsequent years:

Production     Period	Total Hedged Volumes	Description
2009	5.0 Bcf	NYMEX Swaps
2010	19.6 Bcf	NYMEX Swaps
2011	10.7 Bcf	NYMEX Swaps
2012	13.4 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 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for information regarding the Company’s policies on fair value measurement.

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

	September 30, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	76,238		$	76,380		$	152,618
Noncurrent assets		2,432			13,893			16,325
Current liabilities		(25,547	)		(707	)		(26,254	)
Noncurrent liabilities		(9,824	)		(400	)		(10,224	)
Net derivative asset	$	43,299		$	89,166		$	132,465

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	December 31, 2008
(in thousands)	Level 2*			Level 3*		Total
Current assets	$	91,687		$	104,812	$	196,499
Noncurrent assets		91,321			49,282		140,603
Current liabilities		(27,653	)		-		(27,653	)
Noncurrent liabilities		(8,821	)		-		(8,821	)
Net derivative asset	$	146,534		$	154,094	$	300,628

* 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, 2009, Alagasco has $25.9 million and $10.2 million of derivative instruments which are classified as Level 2 fair values and are included in the table as current and noncurrent liabilities, respectively. As of December 31, 2008, Alagasco has $27.7 million and $8.8 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, 2009 and December 31, 2008.

Level 3 assets and liabilities as of September 30, 2009 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 $35 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 three months or nine months ended September 30, 2009. The Company expects any future stock repurchases to be funded through internally generated cash flow or through the utilization of its short-term credit facilities. During the nine months ended September 30, 2009, the Company had noncash purchases of approximately $0.6 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.

Short-Term Credit Facilities

Access to capital is an integral part of the Company’s business plan. While the Company expects to have ongoing access to its short-term credit facilities and the longer-term markets, continued access could be adversely affected by current and future economic and business conditions and credit rating downgrades. To help finance its growth plans and operating needs, the Company currently has available short-term credit facilities as follows:

(in thousands)	Current Term	Energen		Alagasco		Total
Regions Bank	4/23/2010	$	165,000	$	35,000	$	200,000
Wachovia Bank, National Association	6/30/2010		100,000		100,000		100,000
Compass Bank	7/29/2010		70,000		70,000		70,000
RBC Bank (USA)	1/21/2010		20,000		15,000		35,000
Citicorp USA, Inc.	4/16/2010		20,000		15,000		35,000
First Commercial	7/29/2010		-		25,000		25,000
The Bank of New York Mellon	1/22/2010		25,000		-		25,000
The Northern Trust Company	10/13/2010		15,000		25,000		25,000
BancorpSouth Bank	5/26/2010		-		10,000		10,000
Total		$	415,000	$	295,000	$	525,000

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Credit Ratings

In February 2009, Standard and Poor’s (S&P) removed from “CreditWatch with negative implications” the long-term debt ratings of Energen and Alagasco following a review of four diversified energy companies and their subsidiaries. The investment-grade, consolidated rating for Energen and Alagasco was downgraded from BBB+ to BBB; the outlook is “stable.” S&P said the one-notch downgrade primarily reflected a greater weighting of Energen’s exploration and production activities in S&P’s business risk assessment. In addition, S&P said the rating reflected Energen’s “solid credit measures, a favorable discretionary cash flow outlook for 2009, and some cash flow diversification provided by its regulated utility subsidiary.” The downgrade did not have a material impact on the consolidated financial statements or the results of operations. Future borrowing costs and terms may be negatively impacted.

On September 25, 2007, Moody’s Investors Service (Moody’s) downgraded the debt rating of Energen to Baa3 senior unsecured from Baa2. Energen’s debt rating of Baa3 remains investment grade and reflects Moody’s assignment of increased risk exposure related to the growth of its oil and gas operations in contrast to its legacy natural gas distribution assets. Moody’s also confirmed the debt rating of Alagasco during this review as A1 senior unsecured.

Dividends

Energen expects to pay annual cash dividends of $0.50 per share on the Company’s common stock in 2009. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. There have been no material changes to the contractual cash obligations of the Company since December 31, 2008.

Recent Accounting Standards Updates

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

FORWARD LOOKING STATEMENTS AND RISK FACTORS

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.

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

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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 19 percent, 18 percent and 13 percent, respectively, of Energen Resources’ estimated 2009 production. Energen Resources’ other purchasers are each expected to purchase less than 9 percent of estimated 2009 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. 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.

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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)	2009			2008		2009		2008
Oil and Gas Operations
Operating revenues
Natural gas	$	115,227		$	145,283	$	343,684	$	411,453
Oil		80,225			82,375		204,587		221,402
Natural gas liquids		17,496			18,404		48,212		55,915
Other		5,553			1,691		9,675		15,658
Total	$	218,501		$	247,753	$	606,158	$	704,428
Production volumes
Natural gas (MMcf)		18,881			17,258		54,532		50,081
Oil (MBbl)		1,253			1,055		3,456		3,005
Natural gas liquids (MMgal)		20.0			17.8		55.9		52.7
Total production volumes (MMcfe)		29,253			26,134		83,259		75,639
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	6.10		$	8.42	$	6.30	$	8.22
Oil (barrel)	$	64.03		$	78.08	$	59.19	$	73.69
Natural gas liquids (gallon)	$	0.88		$	1.03	$	0.86	$	1.06
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)	$	6.10		$	8.26	$	6.30	$	8.20
Oil (barrel)	$	63.71		$	78.09	$	58.95	$	74.02
Natural gas liquids (gallon)	$	0.88		$	1.03	$	0.86	$	1.06
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	3.06		$	9.03	$	3.34	$	8.91
Oil (barrel)	$	63.59		$	116.81	$	52.17	$	109.77
Natural gas liquids (gallon)	$	0.66		$	1.37	$	0.58	$	1.36
Other data
Lease operating expense (LOE)
LOE and other	$	45,480		$	43,890	$	134,723	$	128,627
Production taxes		9,050			20,610		24,160		58,739
Total	$	54,530		$	64,500	$	158,883	$	187,366
Depreciation, depletion and amortization	$	48,473		$	34,849	$	134,189	$	97,240
Capital expenditures	$	37,596		$	122,597	$	353,424	$	295,507
Exploration expenditures	$	1,120		$	906	$	1,374	$	4,215
Operating income	$	97,682		$	137,270	$	270,277	$	377,852
Natural Gas Distribution
Operating revenues
Residential	$	36,371		$	38,347	$	305,663	$	301,633
Commercial and industrial		20,834			24,121		126,128		133,004
Transportation		12,043			10,816		39,268		37,825
Other		(460	)		9,168		398		16,227
Total	$	68,788		$	82,452	$	471,457	$	488,689

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Gas delivery volumes (MMcf)
Residential		1,498			1,505			15,784		16,247
Commercial and industrial		1,235			1,390			7,613		8,349
Transportation		10,504			10,706			29,775		36,267
Total		13,237			13,601			53,172		60,863
Other data
Depreciation and amortization	$	12,850		$	12,262		$	38,119	$	36,401
Capital expenditures	$	21,133		$	15,959		$	57,107	$	44,955
Operating income (loss)	$	(15,237	)	$	(5,891	)	$	68,844	$	67,125

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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, 2009, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2013.

A failure to meet sales volume targets at Energen Resources or gas supply targets at Alagasco due to miscalculations, weather events, natural disasters, accidents, mechanical failure, criminal act or otherwise could leave the Company or Alagasco exposed to its counterparties in commodity hedging contracts and result in material adverse financial losses.

See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for details related to the Company’s hedging activities.

The Company’s interest rate exposure as of September 30, 2009, 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)	During the period covered by this report, Energen’s natural gas utility, Alabama Gas Corporation, implemented the Customer Care and Service (CCS) software system which replaces a legacy system and provides for the customer accounting and revenue recognition process. This system conversion resulted in changes to internal controls in the financial close process. There were no other changes in our internal controls 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)	During the period covered by this report, Alabama Gas Corporation implemented the CCS software system which replaces a legacy system and provides for the customer accounting and revenue recognition process. This system conversion resulted in changes to internal controls in the financial close process. There were no other changes in our internal controls 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 Progams**
July 1, 2009 through July 31, 2009	-			-	-	8,992,700
August 1, 2009 through August 31, 2009	-			-	-	8,992,700
September 1, 2009 through September 30, 2009	246	*	$	41.90	-	8,992,700
Total	246		$	41.90	-	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, 2009, 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 3, 2009	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 3, 2009	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 3, 2009	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
November 3, 2009	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

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