10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 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.    YES  x    NO  ¨

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

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

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

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

Alabama Gas Corporation - Large accelerated filer  ¨     Accelerated filer  ¨    Non-accelerated filer  x    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 August 3, 2009.

Energen Corporation	$0.01 par value	71,712,913 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 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	24
	Selected Business Segment Data of Energen Corporation	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	36
Item 4.	Controls and Procedures	37
	PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 6.	Exhibits	38
SIGNATURES		39

2

PART I. FINANCIAL INFORMATION

ITEM  1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

ENERGEN CORPORATION

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(in thousands, except per share data)	2009			2008			2009			2008
Operating Revenues
Oil and gas operations	$	198,537		$	231,780		$	387,657		$	456,675
Natural gas distribution		107,683			109,486			402,669			406,237
Total operating revenues		306,220			341,266			790,326			862,912
Operating Expenses
Cost of gas		50,837			55,869			202,906			217,258
Operations and maintenance		88,500			93,427			176,887			179,979
Depreciation, depletion and amortization		56,407			44,114			110,985			86,530
Taxes, other than income taxes		15,168			29,868			41,628			64,773
Accretion expense		1,163			1,055			2,299			2,100
Total operating expenses		212,075			224,333			534,705			550,640
Operating Income		94,145			116,933			255,621			312,272
Other Income (Expense)
Interest expense		(9,788	)		(10,258	)		(19,569	)		(21,380	)
Other income		2,817			486			1,522			730
Other expense		(170	)		(452	)		(360	)		(1,048	)
Total other expense		(7,141	)		(10,224	)		(18,407	)		(21,698	)
Income Before Income Taxes		87,004			106,709			237,214			290,574
Income tax expense		32,003			39,831			86,631			107,008
Net Income	$	55,001		$	66,878		$	150,583		$	183,566
Diluted Earnings Per Average Common Share	$	0.76		$	0.93		$	2.09		$	2.55
Basic Earnings Per Average Common Share	$	0.77		$	0.93		$	2.10		$	2.56
Dividends Per Common Share	$	0.125		$	0.12		$	0.25		$	0.24
Diluted Average Common Shares Outstanding		71,904			72,055			71,888			72,054
Basic Average Common Shares Outstanding		71,644			71,585			71,642			71,611

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

3

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

(in thousands)	June 30, 2009		December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	38,402	$	13,177
Accounts receivable, net of allowance for doubtful accounts of $13,343 at June 30, 2009, and $12,868 at December 31, 2008		294,276		414,362
Inventories, at average cost
Storage gas inventory		55,157		77,243
Materials and supplies		17,210		13,541
Liquified natural gas in storage		3,260		3,219
Regulatory asset		46,508		41,714
Income tax receivable		7,745		50,476
Prepayments and other		12,700		29,309
Total current assets		475,258		643,041
Property, Plant and Equipment
Oil and gas properties, successful efforts method		3,276,013		2,959,665
Less accumulated depreciation, depletion and amortization		880,314		793,465
Oil and gas properties, net		2,395,699		2,166,200
Utility plant		1,196,836		1,166,967
Less accumulated depreciation		496,684		480,601
Utility plant, net		700,152		686,366
Other property, net		15,457		15,082
Total property, plant and equipment, net		3,111,308		2,867,648
Other Assets
Regulatory asset		102,192		97,511
Long-term derivative instruments		52,031		140,603
Deferred charges and other		27,515		26,601
Total other assets		181,738		264,715
TOTAL ASSETS	$	3,768,304	$	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)	June 30, 2009			December 31, 2008
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Notes payable to banks	$	95,000		$	62,000
Accounts payable		116,437			224,309
Accrued taxes		56,178			42,183
Customers’ deposits		21,288			22,081
Amounts due customers		4,475			15,124
Accrued wages and benefits		16,775			24,966
Regulatory liability		7,989			25,363
Royalty payable		13,122			12,275
Deferred income taxes		39,476			41,969
Other		23,894			39,831
Total current liabilities		394,634			510,101
Long-term debt		561,176			561,631
Deferred Credits and Other Liabilities
Asset retirement obligation		75,868			66,151
Pension and other postretirement liabilities		67,118			67,474
Regulatory liability		150,563			147,514
Long-term derivative instruments		13,636			8,821
Deferred income taxes		494,439			482,058
Other		19,829			18,364
Total deferred credits and other liabilities		821,453			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, 74,549,165 shares issued at June 30, 2009, and 74,521,957 shares issued at December 31, 2008		745			745
Premium on capital stock		458,662			454,778
Capital surplus		2,802			2,802
Retained earnings		1,538,947			1,405,970
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges		141,294			200,867
Pension and postretirement plans		(30,033	)		(31,050	)
Deferred compensation plan		3,145			2,948
Treasury stock, at cost; 2,998,492 shares at June 30, 2009, and 2,977,947 shares at December 31, 2008		(124,521	)		(123,770	)
Total shareholders’ equity		1,991,041			1,913,290
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,768,304		$	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)

Six months ended June 30, (in thousands)	2009			2008
Operating Activities
Net income	$	150,583		$	183,566
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		110,985			86,530
Deferred income taxes		45,759			59,892
Change in derivative fair value		(118	)		3,788
Gain on sale of assets		(472	)		(10,374	)
Other, net		5,919			4,137
Net change in:
Accounts receivable, net		95,530			(1,292	)
Inventories		18,376			21,493
Accounts payable		(68,422	)		(6,180	)
Amounts due customers		(10,599	)		(10,698	)
Income tax receivable		42,731			-
Other current assets and liabilities		6,530			(15,501	)
Net cash provided by operating activities		396,802			315,361
Investing Activities
Additions to property, plant and equipment		(200,264	)		(182,052	)
Acquisitions, net of cash acquired		(185,680	)		(15,516	)
Proceeds from sale of assets		939			15,710
Other, net		(1,675	)		(715	)
Net cash used in investing activities		(386,680	)		(182,573	)
Financing Activities
Payment of dividends on common stock		(17,606	)		(17,308	)
Issuance of common stock		184			126
Payment of long-term debt		(548	)		(443	)
Net change in short-term debt		33,000			(131,000	)
Tax benefit on stock compensation		73			16,836
Net cash provided by (used in) financing activities		15,103			(131,789	)
Net change in cash and cash equivalents		25,225			999
Cash and cash equivalents at beginning of period		13,177			8,687
Cash and Cash Equivalents at End of Period	$	38,402		$	9,686

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 June 30,						Six months ended June 30,
(in thousands)	2009			2008			2009			2008
Operating Revenues	$	107,683		$	109,486		$	402,669		$	406,237
Operating Expenses
Cost of gas		50,837			55,869			202,906			217,258
Operations and maintenance		33,236			34,779			64,292			65,434
Depreciation and amortization		12,654			12,119			25,269			24,139
Income taxes
Current		(5,867	)		(3,569	)		20,723			20,508
Deferred		6,060			1,927			8,828			4,404
Taxes, other than income taxes		7,714			8,191			26,121			26,390
Total operating expenses		104,634			109,316			348,139			358,133
Operating Income		3,049			170			54,530			48,104
Other Income (Expense)
Allowance for funds used during construction		340			201			550			326
Other income		1,072			169			554			369
Other expense		(154	)		(247	)		(343	)		(840	)
Total other income (expense)		1,258			123			761			(145	)
Interest Charges
Interest on long-term debt		2,979			2,992			5,961			5,987
Other interest expense		426			394			952			1,391
Total interest charges		3,405			3,386			6,913			7,378
Net Income (Loss)	$	902		$	(3,093	)	$	48,378		$	40,581

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

7

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

(in thousands)	June 30, 2009			December 31, 2008
ASSETS
Property, Plant and Equipment
Utility plant	$	1,196,836		$	1,166,967
Less accumulated depreciation		496,684			480,601
Utility plant, net		700,152			686,366
Other property, net		149			151
Current Assets
Cash and cash equivalents		31,588			9,728
Accounts receivable
Gas		59,089			146,886
Other		8,206			10,014
Affiliated companies		212			-
Allowance for doubtful accounts		(12,500	)		(12,100	)
Inventories, at average cost
Storage gas inventory		55,157			77,243
Materials and supplies		4,241			4,381
Liquified natural gas in storage		3,260			3,219
Deferred income taxes		22,185			22,152
Income tax receivable		1,824			30,654
Regulatory asset		46,508			41,714
Prepayments and other		1,171			2,622
Total current assets		220,941			336,513
Other Assets
Regulatory asset		102,192			97,511
Deferred charges and other		6,795			6,046
Total other assets		108,987			103,557
TOTAL ASSETS	$	1,030,229		$	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)	June 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 June 30, 2009 and December 31, 2008		20		20
Premium on capital stock		31,682		31,682
Capital surplus		2,802		2,802
Retained earnings		304,195		273,743
Total common shareholder’s equity		338,699		308,247
Long-term debt		207,009		207,557
Total capitalization		545,708		515,804
Current Liabilities
Notes payable to banks		-		62,000
Accounts payable		68,404		110,838
Affiliated companies		-		21,582
Accrued taxes		45,060		33,911
Customers’ deposits		21,288		22,081
Amounts due customers		4,475		15,124
Accrued wages and benefits		8,610		10,497
Regulatory liability		7,989		25,363
Other		11,076		9,703
Total current liabilities		166,902		311,099
Deferred Credits and Other Liabilities
Deferred income taxes		111,208		102,473
Pension and other postretirement liabilities		30,418		30,021
Regulatory liability		150,563		147,514
Long-term derivative instruments		13,636		8,821
Other		11,794		10,855
Total deferred credits and other liabilities		317,619		299,684
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	1,030,229	$	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)

Six months ended June 30, (in thousands)	2009			2008
Operating Activities
Net income	$	48,378		$	40,581
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		25,269			24,139
Deferred income taxes		8,828			4,404
Other, net		1,418			2,730
Net change in:
Accounts receivable		72,631			31,105
Inventories		22,185			19,531
Accounts payable		(49,646	)		(11,569	)
Amounts due customers		(10,599	)		(10,698	)
Income tax receivable		28,830			-
Other current assets and liabilities		11,291			9,309
Net cash provided by operating activities		158,585			109,532
Investing Activities
Additions to property, plant and equipment		(33,013	)		(28,620	)
Other, net		(1,444	)		(2,207	)
Net cash used in investing activities		(34,457	)		(30,827	)
Financing Activities
Dividends		(17,926	)		(17,193	)
Payment of long-term debt		(548	)		(443	)
Net advances (to) from affiliates		(21,794	)		273
Net change in short-term debt		(62,000	)		(62,000	)
Net cash used in financing activities		(102,268	)		(79,363	)
Net change in cash and cash equivalents		21,860			(658	)
Cash and cash equivalents at beginning of period		9,728			7,335
Cash and Cash Equivalents at End of Period	$	31,588		$	6,677

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 August 7, 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. 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, 2008, RSE limited the utility’s equity upon which a return is permitted to 57 percent of total capitalization. The equity upon which a return is permitted will be phased down to 55 percent by September 30, 2009.

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.

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 from force 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.

3. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, applies Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended which requires all derivatives to be recognized on the balance sheet and measured 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 under SFAS No. 133 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, 25 percent, 21 percent and 18 percent, respectively, of Energen Resources’ gain on fair value of derivatives. Energen Resources was in a net gain position with all of its counterparties at June 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 June 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 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 under SFAS No. 133 are recorded at fair value with gains or losses recognized in operating revenues in the period of change.

12

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

(in thousands)	June 30, 2009
	Oil and Gas Operations			Natural Gas Distribution			Total
Derivative assets or (liabilities) designated as hedging instruments under SFAS No. 133
Accounts receivable	$	202,027		$	-		$	202,027
Long-term derivative instruments		79,243			-			79,243
Total derivative assets		281,270			-			281,270
Accounts payable		(86	)		-			(86	)
Accounts receivable		(23,640	)*		-			(23,640	)
Long-term derivative instruments		(27,426	)*		-			(27,426	)
Total derivative liabilities		(51,152	)		-			(51,152	)
Total derivatives designated		230,118			-			230,118
Derivative assets or (liabilities) not designated as hedging instruments under SFAS No. 133
Accounts receivable		567			-			567
Long-term derivative instruments		-			214			214
Total derivative assets		567			214			781
Accounts payable		-			(32,496	)		(32,496	)
Long-term derivative instruments		-			(13,636	)		(13,636	)
Total derivative liabilities		-			(46,132	)		(46,132	)
Total derivatives not designated		567			(45,918	)		(45,351	)
Total derivatives	$	230,685		$	(45,918	)	$	184,767

* Amounts classified in accordance with Financial Accounting Standards Board (FASB) Interpretation No. 39 (as amended), “Offsetting of Amounts Related to Certain Contracts” which permits offsetting of fair value of amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $86.6 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 June 30, 2009 and December 31, 2008, respectively.

As required by SFAS No. 133, 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 in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”.

The following table details the effect of derivative commodity instruments in SFAS No. 133 cash flow hedging relationships on the financial statements:

(in thousands)	Location of Gain on Income Statement	Three months ended June 30, 2009			Six months ended June 30, 2009
Amount of gain (loss) recognized in OCI on derivative (effective portion), net of tax of ($55.9) million and $86.6 million	-	$	(91,257	)	$	141,294
Amount of gain reclassified from accumulated OCI into income (effective portion)	Operating revenues	$	69,902		$	139,557
Amount of loss recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	Operating revenues	$	(693	)	$	(492	)

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The following table details the effect of derivative commodity instruments not designated as hedging instruments under SFAS No. 133 on the income statements:

(in thousands)	Location of Gain on Income Statement	Three months ended June 30, 2009		Six months ended June 30, 2009
Amount of gain recognized in income on derivative	Operating revenues	$	436	$	441

As of June 30, 2009, $109.3 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of June 30, 2009, the Company had 0.06 billion cubic feet (Bcf) of gas hedges and 186 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	8.1 Bcf	$8.03 Mcf	NYMEX Swaps
	17.9 Bcf	$7.12 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	2,087 MBbl	$70.91 Bbl	NYMEX Swaps
2010	2,973 MBbl	$88.48 Bbl	NYMEX Swaps
2011	2,556 MBbl	$74.98 Bbl	NYMEX Swaps
2012	852 MBbl	$71.30 Bbl	NYMEX Swaps
2013	336 MBbl	$73.30 Bbl	NYMEX Swaps
Oil Basis Differential
2009	1,535 MBbl	*	Basis Swaps
2010	2,383 MBbl	*	Basis Swaps
2011	2,076 MBbl	*	Basis Swaps
Natural Gas Liquids
2009	21.7 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 transactions for the remainder of 2009 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2009	9.0 Bcf	$6.90 Mcf	NYMEX Swaps
2010	19.6 Bcf	$7.31 Mcf	NYMEX Swaps
2011	10.7 Bcf	$7.30 Mcf	NYMEX Swaps
2012	13.4 Bcf	$7.33 Mcf	NYMEX Swaps

As of June 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.

The Company applies SFAS No. 157, “Fair Value Measurements,” under the provisions of the FASB Staff Position 157-2, “Effective Date of FASB Statement No. 157.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. As defined under SFAS No. 157, 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). SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value defined 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:

	June 30, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	68,655		$	110,299		$	178,954
Noncurrent assets		16,974			35,057			52,031
Current liabilities		(32,413	)		(169	)		(32,582	)
Noncurrent liabilities		(13,332	)		(304	)		(13,636	)
Net derivative asset	$	39,884		$	144,883		$	184,767

	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 FASB Interpretation No. 39.

As of June 30, 2009, Alagasco has $0.2 million, $32.5 million and $13.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as noncurrent assets and 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.

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 June 30, 2009			Six months ended June 30, 2009
Balance at beginning of period	$	191,059		$	154,094
Realized gains		(1,383	)		(1,383	)
Unrealized gains (losses) relating to instruments held at the reporting date		(658	)		74,411
Purchases and settlements during period		(44,135	)		(82,239	)
Balance at end of period	$	144,883		$	144,883

(in thousands)	Three months ended June 30, 2008			Six months ended June 30, 2008
Balance at beginning of period	$	(70,404	)	$	(9,998	)
Realized losses		11,781			15,743
Unrealized losses relating to instruments held at the reporting date		(151,311	)		(214,074	)
Purchases and settlements during period		(6,348	)		(7,953	)
Balance at end of period	$	(216,282	)	$	(216,282	)

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

(in thousands, except per share amounts)	Three months ended June 30, 2009					Three months ended June 30, 2008
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	55,001	71,644	$	0.77	$	66,878	71,585	$	0.93
Effect of dilutive securities
Performance share awards			107					184
Stock options			105					212
Non-vested restricted stock			48					74
Diluted EPS	$	55,001	71,904	$	0.76	$	66,878	72,055	$	0.93

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(in thousands, except per share amounts)	Six months ended June 30, 2009					Six months ended June 30, 2008
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	150,583	71,642	$	2.10	$	183,566	71,611	$	2.56
Effect of dilutive securities
Performance share awards			104					176
Stock options			97					198
Non-vested restricted stock			45					69
Diluted EPS	$	150,583	71,888	$	2.09	$	183,566	72,054	$	2.55

For the three months and six months ended June 30, 2009, the Company had 426,245 and 964,737, respectively, options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months and six months ended June 30, 2008, the Company had 186,700 options that were excluded from the computation of diluted EPS.

5. SEGMENT INFORMATION

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2009			2008			2009			2008
Operating revenues
Oil and gas operations	$	198,537		$	231,780		$	387,657		$	456,675
Natural gas distribution		107,683			109,486			402,669			406,237
Total	$	306,220		$	341,266		$	790,326		$	862,912
Operating income (loss)
Oil and gas operations	$	91,449		$	119,087		$	172,595		$	240,582
Natural gas distribution		3,242			(1,472	)		84,081			73,016
Eliminations and corporate expenses		(546	)		(682	)		(1,055	)		(1,326	)
Total	$	94,145		$	116,933		$	255,621		$	312,272
Other income (expense)
Oil and gas operations	$	(4,896	)	$	(6,964	)	$	(12,164	)	$	(14,162	)
Natural gas distribution		(2,147	)		(3,263	)		(6,152	)		(7,523	)
Eliminations and other		(98	)		3			(91	)		(13	)
Total	$	(7,141	)	$	(10,224	)	$	(18,407	)	$	(21,698	)
Income before income taxes	$	87,004		$	106,709		$	237,214		$	290,574

(in thousands)	June 30, 2009			December 31, 2008
Identifiable assets
Oil and gas operations	$	2,739,180		$	2,650,136
Natural gas distribution		1,030,017			1,126,587
Subtotal		3,769,197			3,776,723
Eliminations and other		(893	)		(1,319	)
Total	$	3,768,304		$	3,775,404

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6. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended June 30,
(in thousands)	2009			2008
Net income	$	55,001		$	66,878
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($29.6) million and ($202.9) million		(48,347	)		(331,094	)
Reclassification adjustment for derivative instruments, net of tax of ($26.3) million and $28.6 million		(42,910	)		46,623
Pension and postretirement plans, net of tax of $0.3 million and $0.3 million		508			516
Comprehensive loss	$	(35,748	)	$	(217,077	)

	Six months ended June 30,
(in thousands)	2009			2008
Net income	$	150,583		$	183,566
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $16.3 million and ($271.7) million		26,647			(443,263	)
Reclassification adjustment for derivative instruments, net of tax of ($52.8) million and $37.7 million		(86,220	)		61,569
Pension and postretirement plans, net of tax of $0.5 million and $0.6 million		1,017			1,031
Comprehensive income (loss)	$	92,027		$	(197,097	)

Accumulated other comprehensive income (loss) consisted of the following:

(in thousands)	June 30, 2009			December 31, 2008
Unrealized gain on hedges, net of tax of $86.6 million and $123.1 million	$	141,294		$	200,867
Pension and postretirement plans, net of tax of ($16.2) million and ($16.7) million		(30,033	)		(31,050	)
Accumulated other comprehensive income	$	111,261		$	169,817

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.

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 $17.73 and $17.09, respectively, as of June 30, 2009.

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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 a fair value of $39.16 as of June 30, 2009. Energen Resources also awarded 2,911 Petrotech units with a three year vesting period and a fair value of $38.68 as of June 30, 2009.

1997 Deferred Compensation Plan

During the three months and six months ended June 30, 2009, the Company had noncash purchases of approximately $16,000 and $0.6 million, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

8. EMPLOYEE BENEFIT PLANS

The Company accounts for defined benefit pension plans and other postretirement benefit plans (benefit plans) in accordance with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R).” SFAS No. 158 requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position effective for fiscal years ending after December 15, 2008. The Company previously 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 June 30,						Six months ended June 30,
(in thousands)	2009			2008			2009			2008
Components of net periodic benefit cost:
Service cost	$	1,835		$	1,790		$	3,670		$	3,580
Interest cost		3,016			2,950			6,032			5,900
Expected long-term return on assets		(3,501	)		(3,289	)		(7,001	)		(6,578	)
Actuarial loss		997			1,071			1,994			2,142
Prior service cost amortization		145			230			289			460
Termination benefit charge		145			-			145			-
Net periodic expense	$	2,637		$	2,752		$	5,129		$	5,504

The Company is not required to make pension contributions in 2009 but expects to make discretionary contributions of approximately $15 million through year-end. For the three months and six months ended June 30, 2009, the Company made benefit payments aggregating $48,000 and $3.7 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $0.2 million 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 Company recognized a settlement charge of $0.7 million in the fourth quarter of 2008 for the payment of lump sums from a defined benefit pension plan. This charge represented an acceleration of the unamortized actuarial losses as required under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.”

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

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2009			2008			2009			2008
Components of net periodic benefit cost:
Service cost	$	453		$	409		$	906		$	818
Interest cost		1,212			1,229			2,425			2,458
Expected long-term return on assets		(885	)		(1,384	)		(1,771	)		(2,768	)
Actuarial loss (gain)		57			(195	)		114			(390	)
Transition amortization		479			479			959			959
Net periodic expense	$	1,316		$	538		$	2,633		$	1,077

For the three months and six months ended June 30, 2009, the Company made contributions aggregating $1.3 million and $2.6 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $2.6 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 $91 million through October 2015. 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 106 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 consolidated balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At June 30, 2009, the fixed price purchases under these guarantees had a maximum term outstanding through June 2010 and an aggregate purchase price of $10.2 million with a market value of $9.2 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 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.

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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; however, remediation of the Huntsville, Alabama manufactured gas plant site discussed below, new regulations, enforcement policies, claims for damages or other events could result in significant 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 expects to enter into a Consent Order and is in discussions with the current site owner to develop an action plan for the site. Based on the limited information available at this time, Alagasco preliminarily estimates that it may incur costs associated with the site ranging from $4 million to $8.2 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 six months ended June 30, 2009, the Company incurred costs of $32,000 and $84,000 associated with the site. As of June 30, 2009, the Company has accrued a contingent liability of $3.9 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 $562,009,000 would be $540,978,000 at June 30, 2009. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, with a carrying value of $207,009,000 would be $193,976,000 at June 30, 2009. The fair values were based on market prices of similar issues having the same remaining maturities, redemption terms and credit rating.

11. REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	June 30, 2009				December 31, 2008
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	132	$	70,703	$	132	$	72,560
Accretion and depreciation for asset retirement obligation		-		13,773		-		13,145
Gas supply adjustment		13,308		-		11,173		-
Risk management activities		32,496		13,636		27,653		8,821
RSE adjustment		511		-		2,688		-
Enhanced stability reserve		-		4,038		-		2,917
Other		61		42		68		68
Total regulatory assets	$	46,508	$	102,192	$	41,714	$	97,511
Regulatory liabilities:
RSE adjustment	$	137	$	-	$	137	$	-
Unbilled service margin		7,818		-		25,192		-
Asset removal costs, net		-		131,931		-		129,579
Asset retirement obligation		-		17,526		-		17,024
Risk management activities		-		215		-		-
Other		34		891		34		911
Total regulatory liabilities	$	7,989	$	150,563	$	25,363	$	147,514

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12. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

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 under SFAS No. 141(R), “Business Combinations.” As such, the Company estimated the fair value of this property as of the acquisition date, as defined in SFAS No. 141(R) to be the date on which the acquirer obtains control of the acquiree, which for this acquisition is June 30, 2009 (the closing date). SFAS No. 157 defines fair value as 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). Further, SFAS No. 157 emphasizes that fair value measurements 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 under SFAS No. 157.

In applying these accounting principles the Company estimated the fair value of these properties on the acquisition date to be approximately $186.8 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 in accordance with the provisions of SFAS No. 141(R).

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 is not complete.

(in thousands)	June 30, 2009
Consideration given to Range Resources
Cash	$	181,837
Recognized amounts of identifiable assets acquired and liabilities assumed
Property developed properties	$	182,979
Unproved leasehold properties		3,800
Accounts receivable		5,262
Inventory and other		455
Asset retirement obligation		(6,590	)
Environmental liabilities		(3,124	)
Accounts payable		(945	)
Total identifiable net assets	$	181,837

Summarized below are the consolidated results of operations for the three months and six months ended June 30,

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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 six months ended June 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.

	Three months ended June 30,				Six months ended June 30,
(in thousands)	2009		2008		2009		2008
Operating revenues	$	316,889	$	370,406	$	809,022	$	912,426
Operating income	$	97,743	$	136,790	$	260,101	$	343,830

During the six months ended June 30, 2009, Energen Resources capitalized approximately $4.2 million of unproved leaseholds costs, approximately $165,000 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.

13. RECENTLY ISSUED ACCOUNTING STANDARDS

As of January 1, 2008, the Company adopted the provisions of SFAS No. 157 as permitted by FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157,” for financial assets and liabilities. SFAS No. 157 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 provisions of SFAS No. 157 related to non-financial assets and liabilities with no impact to the Company’s consolidated financial statements or the results of operations.

The FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” in December 2007. SFAS No. 160 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. SFAS No. 160 also establishes disclosure requirements that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. This Standard did not have an effect on the consolidated financial statements or the results of operations of the Company.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “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 SFAS No. 141R, 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. SFAS No. 141R was effective January 1, 2009 and has been applied to an acquisition made during the second quarter of 2009 (see Note 12, Acquisition and Dispositions of Oil and Gas Properties).

In March 2008, the FASB issued SFAS No. 161, “Disclosures About Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” SFAS No. 161 expands quarterly disclosure requirements in SFAS No. 133 about an entity’s derivative instruments and hedging activities. SFAS No. 161 is effective for years beginning after November 1, 2008. The additional disclosures for derivative instruments required under SFAS No. 161 are included in Note 3, Derivative Commodity Instruments.

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In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) No. 03-06-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in the calculation of EPS under the two-class method as described in SFAS No. 128, “Earnings per Share.” This FSP was effective as of January 1, 2009 and did not have a material impact on the consolidated financial statements or the results of operations of the Company.

In December 2008, the FASB issued FSP 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets,” which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. FSP 132(R)-1 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 FSP 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.

In April 2009, the FASB issued FSP 107-1 and Accounting Principles Board (APB) Opinion No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which requires disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements. FSP 107-1 and APB 28-1 are effective for interim and annual reporting periods ending after June 15, 2009. The implementation of FSP 107-1 and APB 28-1 did not have a material impact on the consolidated financial statements or the results of operations.

During April 2009, the FASB issued FSP 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,” which provides additional guidance for estimating fair value in accordance with SFAS No. 157 when the volume and level of activity for the asset or liability have significantly decreased. This FSP is effective for interim and annual reporting periods ending after June 15, 2009. This FSP did not have an effect on the consolidated financial statements or the results of operations of the Company.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events,” which establishes principles and requirements for subsequent events. This Statement is effective for interim and annual reporting periods ending after June 15, 2009. The additional disclosures for subsequent events required under SFAS No. 165 are included in Note 1, Commitments and Contingencies.

In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R).” SFAS No. 167 amends certain requirements of FASB Interpretation No. 46(R) to improve financial reporting by companies involved with variable interest entities and to provide more relevant and reliable information to users of financial statements. SFAS No. 167 is effective for fiscal years beginning after November 15, 2009. The Company is currently evaluating the impact of the Statement.

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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 $55 million ($0.76 per diluted share) for the three months ended June 30, 2009 compared with net income of $66.9 million ($0.93 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen’s oil and gas subsidiary, had net income for the three months ended June 30, 2009, of $54.9 million as compared with $70.6 million in the same quarter in the previous year. Significantly lower commodity prices (approximately $35 million after-tax) and increased depreciation, depletion and amortization (DD&A) expense (approximately $7 million after-tax) were partially offset by increased natural gas, oil and natural gas liquids production volumes (approximately $13 million after-tax), lower production taxes (approximately $9 million after-tax) and decreased exploration expense (approximately $2 million after-tax). Current-quarter results also include a $1.7 million after-tax insurance settlement associated with its business interruption claim following a natural gas processing plant fire in November 2007. Energen’s natural gas utility, Alagasco, reported net income of $0.9 million in the second quarter of 2009 compared to a net loss of $3.1 million in the same period last year largely reflecting the utility’s ability to earn on a higher level of equity, lower operations and maintenance (O&M) expense, increased revenue from cycle sales partially offset by decreased revenue from large commercial and industrial customers.

For the 2009 year-to-date, Energen’s net income totaled $150.6 million ($2.09 per diluted share) and compared to net income of $183.6 million ($2.55 per diluted share) for the same period in the prior year. Energen Resources generated net income for the six months ended June 30, 2009, of $102 million as compared with $143.1 million in the previous period primarily as a result of lower commodity prices (approximately $63 million after-tax), higher DD&A expense (approximately $15 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 $3 million after-tax). Positively affecting net income was the impact of increased production volumes (approximately $26 million after-tax), decreased production taxes (approximately $14 million after-tax), lower exploration expense (approximately $2 million after-tax) and the $1.7 million after-tax insurance settlement discussed above. Alagasco’s net income of $48.4 million in the current year-to-date compared to net income of $40.6 million in the same period in the previous year primarily due to the same reasons discussed above.

Oil and Gas Operations

Revenues from oil and gas operations declined 14.3 percent to $198.5 million for the three months ended June 30, 2009 and 15.1 percent to $387.7 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 24 percent to $6.27 per thousand cubic feet (Mcf), while oil revenue per unit of production decreased 19.7 percent to $59.85 per barrel. Natural gas liquids revenue per unit of production decreased 20.7 percent to an average price of $0.88 per gallon. In the year-to-date, revenue per unit of production for natural gas declined 21 percent to $6.41 per Mcf, oil revenue per unit of production decreased 20.9 percent to $56.44 per barrel and natural gas liquids revenue per unit of production fell 21.3 percent to an average price of $0.85 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 partially offset by normal production declines. Natural gas production in the second quarter rose 9.8 percent to 18 billion cubic feet (Bcf), oil volumes increased 10.6 percent to 1,113 thousand barrels (MBbl) and natural gas liquids production increased 1.7 percent to 18.4 million gallons (MMgal). For the year-to-date, natural gas production from continuing operations increased 8.6 percent to 35.7 Bcf, while oil volumes rose 13 percent to 2,203 MBbl. Natural gas liquids production increased 2.9 percent to 35.9 MMgal. Natural gas comprised approximately 66 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 $0.3 million in the first quarter of 2009 on the sale of various properties. In the second quarter of 2008, Energen Resources recorded a pre-tax loss of $0.2 million and a pre-tax gain of $10.1 million in the year-to-date largely from the sale of certain Permian Basin oil properties.

O&M expense decreased $3.2 million for the quarter and $1.7 million in the year-to-date. Lease operating expense (excluding production taxes) increased by $1.8 million for the quarter largely due to increased ad valorem taxes (approximately $1.7 million) and higher labor costs (approximately $1 million) partially offset by lower electrical costs (approximately $1.3 million). In the year-to-date, lease operating expense (excluding production taxes) rose $4.5 million primarily due to increased ad valorem taxes (approximately $3.4 million), higher non-operated costs (approximately $2 million), and increased labor costs (approximately $1 million) partially offset by decreased electrical costs (approximately $1 million) and lower repairs and maintenance expense (approximately $0.8 million). Administrative expense decreased $2.2 million for the three months ended June 30, 2009 primarily due to lower benefit costs primarily related to the Company’s performance-based compensation plans. For the six months ended June 30, 2009, administrative expense declined $3.1 million largely due to insurance recoveries associated with certain legal expenses along with lower benefit costs as described above. Exploration expense declined $2.9 million and $3.1 million in the second quarter of 2009 and in the year-to-date, respectively, 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 $11.8 million and increased $23.3 million year-to-date. The average depletion rate for the current quarter was $1.57 per thousand cubic feet equivalent (Mcfe) as compared to $1.25 per Mcfe in the same period a year ago. For the six months ended June 30, 2009, the average depletion rate was $1.56 per Mcfe as compared to $1.23 per Mcfe in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $7.7 million and $15.7 million, respectively, was largely due to higher rates resulting from an increase in development costs and the negative effect on reserves of lower year-end oil and gas prices. Increased production volumes also contributed approximately $4.1 million and $7.6 million to the increase in DD&A expense in the three months and six months ended June 30, 2009, respectively.

Energen Resources’ expense for taxes other than income taxes was $14.2 million and $22.9 million lower in the three months and six months ended June 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 $16.3 million and $26.5 million, respectively, to the decrease in production-related taxes. Increasing production-related taxes were higher production volumes which contributed approximately $2 million and $3.5 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

As discussed more fully in Note 2, Regulatory Matters, in the Notes to Unaudited Condensed Financial Statements, 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 will limit the utility’s equity upon which a return is permitted to 55 percent of total capitalization.

Natural gas distribution revenues declined $1.8 million for the quarter largely due to a decline in gas costs and a decrease in customer usage. Weather that was 13.6 percent warmer than in the same quarter in the prior year contributed to a 3.6 percent decrease in residential sales volumes while commercial and industrial customer sales volumes declined 8.7 percent. Transportation volumes declined 26.3 percent in period comparisons due primarily to decreased large customer and industrial usage. Revenues for the year-to-date declined $3.6 million primarily due to decreased customer usage along with lower gas costs. For the year-to-date, weather was 5 percent warmer compared to the same period last year. Residential sales volumes declined 3.1 percent, commercial and industrial customer sales volumes decreased 8.3 percent and transportation volumes fell 24.6 percent in period comparisons. A decrease in gas costs partially offset by a rise in gas purchase volumes resulted in a 9 percent decrease in cost of gas for the quarter. For the year-to-date, lower gas costs combined with decreased gas purchase volumes contributed to a 6.6 percent decrease in cost of gas. Utility gas costs include commodity cost, risk management

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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 declined 4.4 percent in the current quarter primarily due to decreased consulting and technology fees (approximately $0.9 million), lower distribution operation expenses (approximately $0.8 million) and decreased bad debt expense (approximately $0.7 million) partially offset by increased marketing expenses (approximately $0.7 million). In the six months ended June 30, 2009, O&M expense decreased 1.7 percent. Decreased consulting fees (approximately $1.4 million) and lower distribution operation expenses (approximately $1.3 million) were partially offset by increased insurance costs (approximately $1.8 million).

A 4.4 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 $0.5 million in the first quarter of 2009 and $1.8 million in the year-to-date largely due to lower borrowings at Energen Resources combined with lower interest rates on short-term borrowings. Income tax expense for the Company decreased $7.8 million in the current quarter and $20.4 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 $396.8 million as compared to $315.4 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. These decreases were more than offset by lower working capital requirements which were influenced primarily by income tax receivables along with commodity prices and the timing of payments.

The Company had a net outflow of cash from investing activities of $386.7 million for the six months ended June 30, 2009 primarily due to additions of property, plant and equipment. Energen Resources invested $354.1 million (includes approximately $48.4 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. Utility capital expenditures totaled $33 million (excludes approximately $2.4 million of accrued capital cost) in the year-to-date and primarily represented expansion and replacement of its distribution system and support facilities.

The Company provided $15.1 million from net financing activities in the year-to-date primarily due to the increase in short-term debt borrowings partially offset by the payment of dividends to common shareholders.

FUTURE CAPITAL RESOURCES AND LIQUIDITY

Recent Market Events

Capital and credit markets experienced significant volatility and disruption during 2008. If such economic disruptions were to worsen during 2009, 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

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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 eight financial institutions aggregating $500 million of which Energen has available $230 million, Alagasco has available $85 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 weather, natural disasters, changes in global economics and political unrest will continue to contribute to increased price volatility in the near term. 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 $430 million, including $216 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 does not anticipate significant development costs during 2009 for this acquisition.

The Company also may allocate additional capital for other oil and gas activities such as further 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.

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 343,000 acres representing multiple shale opportunities. As of June 30, 2009, Energen Resources had approximately $42 million of unproved leasehold costs related to its lease position in Alabama shales.

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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. Included in the capital spending estimates above, the Company plans to invest approximately $10 million during 2009 to drill additional shale wells, test alternative completion techniques and complete other zones in the existing test wells.

Energen Resources plans to drill a new well targeting the Chattanooga shale formation in Alabama prior to the end of 2009. Of the above mentioned $42 million of unproved leasehold costs for Alabama shales, approximately $15 million of unproved leasehold costs are associated with the Chattanooga shale formation. The Company continues to pursue a partner as it seeks to unlock the potential of the Conasauga and Chattanooga shales on its extensive acreage position.

Natural Gas Distribution

In recent years, the higher price commodity environment has been a major factor in the decline in the utility’s customer base of approximately 1% annually and in continuing declines in usage volume per customer. The recent lower commodity price environment has not yet reversed this adverse trend at the utility. A return of natural gas prices to higher levels could result in a further decline in Alagasco’s customer base and usage and in significant 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 usage decline 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 impacted by natural gas prices and the economy.

Alagasco maintains an investment in storage gas that is expected to average approximately $54 million in 2009 but will vary depending upon the price of natural gas. During 2009, Alagasco plans to invest an estimated $75 million 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 under SFAS No. 133 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 June 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 June 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.

Alagasco also enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. As required by SFAS No. 133, 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 in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”.

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	8.1 Bcf	$8.03 Mcf	NYMEX Swaps
	17.9 Bcf	$7.12 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

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Oil
2009	2,087 MBbl	$70.91 Bbl	NYMEX Swaps
2010	2,973 MBbl	$88.48 Bbl	NYMEX Swaps
2010	*492 MBbl	$76.30 Bbl	NYMEX Swaps
2011	2,556 MBbl	$74.98 Bbl	NYMEX Swaps
2011	*456 MBbl	$79.50 Bbl	NYMEX Swaps
2012	852 MBbl	$71.30 Bbl	NYMEX Swaps
2013	336 MBbl	$73.30 Bbl	NYMEX Swaps
Oil Basis Differential
2009	1,535 MBbl	**	Basis Swaps
2010	2,383 MBbl	**	Basis Swaps
2011	2,076 MBbl	**	Basis Swaps
Natural Gas Liquids
2009	21.7 MMGal	$1.15 Gal	Liquids Swaps
*       Contracts entered into subsequent to June 30, 2009 **     Average contract prices are not meaningful due to the varying nature of each contract.

Alagasco 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	9.0 Bcf	$6.90 Mcf	NYMEX Swaps
2010	19.6 Bcf	$7.31 Mcf	NYMEX Swaps
2011	10.7 Bcf	$7.30 Mcf	NYMEX Swaps
2012	13.4 Bcf	$7.33 Mcf	NYMEX Swaps

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

The Company has adopted SFAS No. 157, “Fair Value Measurements,” under the provisions of the Financial Accounting Standards Board (FASB) Staff Position 157-2, “Effective Date of FASB Statement No. 157.” See Note 3, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for information regarding SFAS No. 157.

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

	June 30, 2009
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	68,655		$	110,299		$	178,954
Noncurrent assets		16,974			35,057			52,031
Current liabilities		(32,413	)		(169	)		(32,582	)
Noncurrent liabilities		(13,332	)		(304	)		(13,636	)
Net derivative asset	$	39,884		$	144,883		$	184,767

	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 FASB Interpretation No. 39 (as amended), “Offsetting of Amounts Related to Certain Contracts” which permits offsetting of fair value of amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of June 30, 2009, Alagasco has $0.2 million, $32.5 million and $13.6 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as noncurrent assets and 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.

Level 3 assets and liabilities as of June 30, 2009 represent approximately 4 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

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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 $36 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 under SFAS No. 133. 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 six months ended June 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 six months ended June 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	10/31/2009		100,000		100,000		100,000
Compass Bank	7/29/2010		70,000		70,000		70,000
RBC Bank (USA)	10/21/2009		20,000		15,000		35,000
Citicorp USA, Inc.	4/16/2010		20,000		15,000		35,000
The Bank of New York Mellon	1/22/2010		25,000		—		25,000
The Northern Trust Company	10/14/2009		15,000		25,000		25,000
BancorpSouth Bank	5/26/2010		—		10,000		10,000
		$	415,000	$	270,000	$	500,000

The short-term credit facility with First Commercial Bank for $25 million at Alagasco expired on July 31, 2009 and is currently in the renewal process. The Company expects to complete its renewal in the third quarter. The Company also regularly provides information to corporate rating agencies related to current business activities and future performance expectations.

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.

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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 Pronouncements of the Financial Accounting Standards Board

See Note 13, Recently Issued Accounting Standards, in the Notes to Unaudited Condensed Financial Statements for information regarding recently issued accounting standards.

FORWARD LOOKING STATEMENTS

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 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.

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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.

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.

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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.

Complex 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. Further, these laws and regulations could change in ways that substantially increase costs or limit operations.

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SELECTED BUSINESS SEGMENT DATA

ENERGEN CORPORATION

(Unaudited)

	Three months ended June 30,				Six months ended June 30,
(in thousands, except sales price data)	2009		2008		2009		2008
Oil and Gas Operations
Operating revenues
Natural gas	$	112,822	$	135,216	$	228,457	$	266,170
Oil		66,620		74,928		124,362		139,027
Natural gas liquids		16,194		20,065		30,716		37,511
Other		2,901		1,571		4,122		13,967
Total	$	198,537	$	231,780	$	387,657	$	456,675
Production volumes
Natural gas (MMcf)		18,001		16,396		35,651		32,823
Oil (MBbl)		1,113		1,006		2,203		1,950
Natural gas liquids (MMgal)		18.4		18.1		35.9		34.9
Total production volumes (MMcfe)		27,314		25,022		54,006		49,505
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	6.27	$	8.25	$	6.41	$	8.11
Oil (barrel)	$	59.85	$	74.51	$	56.44	$	71.31
Natural gas liquids (gallon)	$	0.88	$	1.11	$	0.85	$	1.08
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)	$	6.27	$	8.37	$	6.41	$	8.17
Oil (barrel)	$	59.46	$	74.50	$	56.25	$	71.83
Natural gas liquids (gallon)	$	0.88	$	1.11	$	0.85	$	1.08
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	2.99	$	9.90	$	3.48	$	8.85
Oil (barrel)	$	55.12	$	118.27	$	45.67	$	105.95
Natural gas liquids (gallon)	$	0.59	$	1.44	$	0.54	$	1.36
Other data
Lease operating expense (LOE)
LOE and other	$	43,371	$	41,602	$	89,243	$	84,737
Production taxes		7,269		21,553		15,110		38,129
Total	$	50,640	$	63,155	$	104,353	$	122,866
Depreciation, depletion and amortization	$	43,753	$	31,995	$	85,716	$	62,391
Capital expenditures	$	241,213	$	98,513	$	315,828	$	172,910
Exploration expenditures	$	104	$	2,960	$	254	$	3,309
Operating income	$	91,449	$	119,087	$	172,595	$	240,582
Natural Gas Distribution
Operating revenues
Residential	$	64,764	$	63,711	$	269,292	$	263,286
Commercial and industrial		29,918		31,378		105,294		108,883
Transportation		12,209		11,506		27,225		27,009
Other		792		2,891		858		7,059
Total	$	107,683	$	109,486	$	402,669	$	406,237

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Gas delivery volumes (MMcf)
Residential		3,095		3,211			14,286		14,742
Commercial and industrial		1,810		1,983			6,378		6,959
Transportation		8,302		11,264			19,271		25,561
Total		13,207		16,458			39,935		47,262
Other data
Depreciation and amortization	$	12,654	$	12,119		$	25,269	$	24,139
Capital expenditures	$	19,864	$	15,926		$	35,974	$	28,996
Operating income (loss)	$	3,242	$	(1,472	)	$	84,081	$	73,016

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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 under Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” 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. These counterparties are believed to be creditworthy by the Company and have agreed in certain instances to post collateral with the Company when unrealized gains on hedges exceed certain specified contractual amounts. Notwithstanding these agreements, the Company is at risk for economic loss based upon the creditworthiness of its counterparties. All hedge transactions are subject to the Company’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. As of June 30, 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 June 30, 2009, was minimal as all long-term debt obligations were at fixed rates.

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ITEM 4. CONTROLS AND PROCEDURES

(a)	Our chief executive officer and chief financial officer have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
(b)	Our chief executive officer and chief financial officer have concluded that during the period covered by this report there were no 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**
April 1, 2009 through April 30, 2009	-			-	-	8,992,700
May 1, 2009 through May 31, 2009	-			-	-	8,992,700
June 1, 2009 through June 30, 2009	420	*	$	38.45	-	8,992,700
Total	420		$	38.45	-	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	–	Section 906 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 June 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
August 7, 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
August 7, 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
August 7, 2009	By	/s/ Russell E. Lynch, Jr.
		Russell E. Lynch, Jr.
		Vice President and Controller of Energen Corporation
August 7, 2009	By	/s/ William D. Marshall
		William D. Marshall
		Vice President and Controller of Alabama Gas Corporation

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EX-31.(A)

CERTIFICATION Exhibit 31(a)

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

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

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

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

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

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

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

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

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

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

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

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

August 7, 2009	By	/s/ J. T. McManus, II
		J. T. McManus, II
		Chairman, Chief Executive Officer and President of Energen Corporation

EX-31.(B)

CERTIFICATION Exhibit 31(b)

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

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

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

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

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

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

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

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

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

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

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

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

August 7, 2009	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation

EX-31.(C)

CERTIFICATION Exhibit 31(c)

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

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

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

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

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

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

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

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

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

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

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

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

August 7, 2009	By	/s/ J. T. McManus, II
		J. T. McManus, II
		Chairman and Chief Executive Officer of Alabama Gas Corporation

EX-31.(D)

CERTIFICATION Exhibit 31(d)

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

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

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

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

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

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

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

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

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

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

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

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

August 7, 2009	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Alabama Gas Corporation

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Energen Corporation and Alabama Gas Corporation (the “Registrants”) on Form 10-Q for the period ended June 30, 2009, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies with respect to each registrant, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge, the Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated as of August 7, 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
By	/s/ Charles W. Porter, Jr.
	Charles W. Porter, Jr. Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation

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