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, 2008

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 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 4, 2008.

Energen Corporation	$0.01 par value	71,698,333 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, 2008

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	22
	Selected Business Segment Data of Energen Corporation	31
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32
Item 4.	Controls and Procedures	33
PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 6.	Exhibits	34
SIGNATURES		35

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)	2008			2007			2008			2007
Operating Revenues
Oil and gas operations	$	231,780		$	203,356		$	456,675		$	397,389
Natural gas distribution		109,486			111,566			406,237			410,194
Total operating revenues		341,266			314,922			862,912			807,583
Operating Expenses
Cost of gas		55,869			53,358			217,258			221,496
Operations and maintenance		93,427			84,111			179,979			166,154
Depreciation, depletion and amortization		44,114			38,707			86,530			76,727
Taxes, other than income taxes		29,868			21,870			64,773			52,182
Accretion expense		1,055			971			2,100			1,921
Total operating expenses		224,333			199,017			550,640			518,480
Operating Income		116,933			115,905			312,272			289,103
Other Income (Expense)
Interest expense		(10,258	)		(12,016	)		(21,380	)		(24,237	)
Other income		486			950			730			1,511
Other expense		(452	)		(187	)		(1,048	)		(382	)
Total other expense		(10,224	)		(11,253	)		(21,698	)		(23,108	)
Income From Continuing Operations Before Income Taxes		106,709			104,652			290,574			265,995
Income tax expense		39,831			36,749			107,008			94,211
Income From Continuing Operations		66,878			67,903			183,566			171,784
Discontinued Operations, Net of Taxes
Income from discontinued operations		-			-			-			1
Income From Discontinued Operations		-			-			-			1
Net Income	$	66,878		$	67,903		$	183,566		$	171,785
Diluted Earnings Per Average Common Share
Continuing operations	$	0.93		$	0.94		$	2.55		$	2.38
Discontinued operations		-			-			-			-
Net Income	$	0.93		$	0.94		$	2.55		$	2.38
Basic Earnings Per Average Common Share
Continuing operations	$	0.93		$	0.95		$	2.56		$	2.40
Discontinued operations		-			-			-			-
Net Income	$	0.93		$	0.95		$	2.56		$	2.40
Dividends Per Common Share	$	0.12		$	0.115		$	0.24		$	0.23
Diluted Average Common Shares Outstanding		72,055			72,249			72,054			72,153
Basic Average Common Shares Outstanding		71,585			71,592			71,611			71,538

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

3

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

(in thousands)	June 30, 2008		December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents	$	9,686	$	8,687
Accounts receivable, net of allowance for doubtful accounts of $13,356 at June 30, 2008, and $12,244 at December 31, 2007		237,814		254,154
Inventories, at average cost
Storage gas inventory		58,539		78,064
Materials and supplies		11,905		13,711
Liquified natural gas in storage		3,340		3,502
Regulatory asset		3,717		10,232
Deferred income taxes		194,174		54,166
Prepayments and other		25,661		26,514
Total current assets		544,836		449,030
Property, Plant and Equipment
Oil and gas properties, successful efforts method		2,689,611		2,530,049
Less accumulated depreciation, depletion and amortization		721,933		664,290
Oil and gas properties, net		1,967,678		1,865,759
Utility plant		1,138,026		1,108,392
Less accumulated depreciation		465,813		448,053
Utility plant, net		672,213		660,339
Other property, net		13,912		12,145
Total property, plant and equipment, net		2,653,803		2,538,243
Other Assets
Regulatory asset		31,940		32,238
Prepaid pension costs and postretirement assets		18,393		20,054
Deferred charges and other		35,737		40,088
Total other assets		86,070		92,380
TOTAL ASSETS	$	3,284,709	$	3,079,653

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

4

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

(in thousands, except share and per share data)	June 30, 2008			December 31, 2007
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	10,000		$	10,000
Notes payable to banks		3,000			134,000
Accounts payable		621,773			259,836
Accrued taxes		40,701			40,857
Customers’ deposits		20,782			21,425
Amounts due customers		6,490			20,534
Accrued wages and benefits		24,845			25,410
Regulatory liability		11,729			32,154
Other		74,241			62,014
Total current liabilities		813,561			606,230
Long-term debt		562,009			562,365
Deferred Credits and Other Liabilities
Asset retirement obligation		62,112			60,571
Pension liabilities		28,951			31,985
Regulatory liability		147,564			141,123
Long-term derivative instruments		295,596			47,093
Deferred income taxes		204,968			238,706
Other		12,382			12,922
Total deferred credits and other liabilities		751,573			532,400
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, 74,504,085 shares issued at June 30, 2008, and 74,190,786 shares issued at December 31, 2007		745			742
Premium on capital stock		455,266			434,999
Capital surplus		2,802			2,802
Retained earnings		1,286,074			1,119,816
Accumulated other comprehensive loss, net of tax
Unrealized losses on hedges		(446,750	)		(65,057	)
Pension and postretirement plans		(20,137	)		(21,167	)
Deferred compensation plan		3,266			16,121
Treasury stock, at cost; 2,995,804 shares at June 30, 2008, and 3,374,336 shares at December 31, 2007		(123,700	)		(109,598	)
Total shareholders’ equity		1,157,566			1,378,658
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,284,709		$	3,079,653

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

5

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

ENERGEN CORPORATION

(Unaudited)

Six months ended June 30, (in thousands)	2008			2007
Operating Activities
Net income	$	183,566		$	171,785
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		86,530			76,727
Deferred income taxes		59,892			1,307
Change in derivative fair value		3,788			(1,574	)
Gain on sale of assets		(10,374	)		(76	)
Other, net		4,137			11,318
Net change in:
Accounts receivable, net		(1,292	)		87,292
Inventories		21,493			2,005
Accounts payable		(6,180	)		(70,297	)
Amounts due customers		(10,698	)		5,118
Other current assets and liabilities		(15,501	)		748
Net cash provided by operating activities		315,361			284,353
Investing Activities
Additions to property, plant and equipment		(182,052	)		(156,730	)
Acquisitions, net of cash acquired		(15,516	)		(31,299	)
Proceeds from sale of assets		15,710			678
Other, net		(715	)		(1,363	)
Net cash used in investing activities		(182,573	)		(188,714	)
Financing Activities
Payment of dividends on common stock		(17,308	)		(16,548	)
Issuance of common stock		126			1,171
Payment of long-term debt		(443	)		(154,791	)
Proceeds from issuance of long-term debt		-			45,000
Debt issuance costs		-			(494	)
Net change in short-term debt		(131,000	)		25,000
Tax benefit on stock compensation		16,836			2,487
Other		-			1,003
Net cash used in financing activities		(131,789	)		(97,172	)
Net change in cash and cash equivalents		999			(1,533	)
Cash and cash equivalents at beginning of period		8,687			10,307
Cash and Cash Equivalents at End of Period	$	9,686		$	8,774

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

6

CONDENSED STATEMENTS OF INCOME

ALABAMA GAS CORPORATION

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
(in thousands)	2008			2007			2008			2007
Operating Revenues	$	109,486		$	111,566		$	406,237		$	410,194
Operating Expenses
Cost of gas		55,869			53,358			217,258			221,496
Operations and maintenance		34,779			33,375			65,434			65,732
Depreciation and amortization		12,119			11,707			24,139			23,254
Income taxes
Current		(3,569	)		910			20,508			25,298
Deferred, net		1,927			(278	)		4,404			(593	)
Taxes, other than income taxes		8,191			8,156			26,390			26,305
Total operating expenses		109,316			107,228			358,133			361,492
Operating Income		170			4,338			48,104			48,702
Other Income (Expense)
Allowance for funds used during construction		201			175			326			312
Other income		169			424			369			903
Other expense		(247	)		(161	)		(840	)		(350	)
Total other income (expense)		123			438			(145	)		865
Interest Charges
Interest on long-term debt		2,992			3,029			5,987			5,993
Other interest expense		394			369			1,391			1,867
Total interest charges		3,386			3,398			7,378			7,860
Net Income (Loss)	$	(3,093	)	$	1,378		$	40,581		$	41,707

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

7

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

(in thousands)	June 30, 2008			December 31, 2007
ASSETS
Property, Plant and Equipment
Utility plant	$	1,138,026		$	1,108,392
Less accumulated depreciation		465,813			448,053
Utility plant, net		672,213			660,339
Other property, net		154			157
Current Assets
Cash and cash equivalents		6,677			7,335
Accounts receivable
Gas		91,468			139,761
Other		6,893			6,336
Allowance for doubtful accounts		(12,500	)		(11,500	)
Inventories, at average cost
Storage gas inventory		58,539			78,064
Materials and supplies		4,022			3,866
Liquified natural gas in storage		3,340			3,502
Deferred income taxes		24,940			25,179
Regulatory asset		3,717			10,232
Prepayments and other		1,464			2,247
Total current assets		188,560			265,022
Other Assets
Regulatory asset		31,940			32,238
Prepaid pension costs and postretirement assets		14,840			15,831
Deferred charges and other		6,970			7,226
Total other assets		53,750			55,295
TOTAL ASSETS	$	914,677		$	980,813

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, 2008		December 31, 2007
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, 2008 and December 31, 2007		20		20
Premium on capital stock		31,682		31,682
Capital surplus		2,802		2,802
Retained earnings		285,367		261,979
Total common shareholder’s equity		319,871		296,483
Long-term debt		208,024		208,467
Total capitalization		527,895		504,950
Current Liabilities
Notes payable to banks		-		62,000
Accounts payable		68,123		80,067
Affiliated companies		5,207		4,934
Accrued taxes		42,588		30,858
Customers’ deposits		20,782		21,425
Amounts due customers		6,490		20,534
Accrued wages and benefits		8,316		10,062
Regulatory liability		11,729		32,154
Other		9,603		10,417
Total current liabilities		172,838		272,451
Deferred Credits and Other Liabilities
Deferred income taxes		63,967		59,790
Regulatory liability		147,564		141,123
Other		2,413		2,499
Total deferred credits and other liabilities		213,944		203,412
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	914,677	$	980,813

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)	2008			2007
Operating Activities
Net income	$	40,581		$	41,707
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		24,139			23,254
Deferred income taxes		4,404			(593	)
Other, net		2,730			2,570
Net change in:
Accounts receivable		31,105			63,939
Inventories		19,531			3,391
Accounts payable		(11,569	)		(44,726	)
Amounts due customers		(10,698	)		5,118
Other current assets and liabilities		9,309			12,880
Net cash provided by operating activities		109,532			107,540
Investing Activities
Additions to property, plant and equipment		(28,620	)		(31,214	)
Net advances to affiliates		-			(3,312	)
Other, net		(2,207	)		(1,126	)
Net cash used in investing activities		(30,827	)		(35,652	)
Financing Activities
Dividends		(17,193	)		(16,395	)
Payment of long-term debt		(443	)		(44,791	)
Proceeds from issuance of long-term debt		-			45,000
Debt issuance costs		-			(494	)
Net advances from (to) affiliates		273			(18,130	)
Net change in short-term debt		(62,000	)		(42,000	)
Other		-			1,003
Net cash used in financing activities		(79,363	)		(75,807	)
Net change in cash and cash equivalents		(658	)		(3,919	)
Cash and cash equivalents at beginning of period		7,335			8,765
Cash and Cash Equivalents at End of Period	$	6,677		$	4,846

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, 2007, 2006 and 2005 included in the 2007 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.

2. REGULATORY MATTERS

All of Alagasco’s utility operations are conducted in the state of Alabama. 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 was extended in 2007, 2002, 1996, 1990, 1987 and 1985. On December 21, 2007, the APSC extended Alagasco’s rate-setting methodology, RSE, with certain modifications as outlined below, for a seven-year period through December 31, 2014. Under the terms of the extension, RSE will continue after December 31, 2014, unless, after notice to the Company and a hearing, the APSC votes to either modify or discontinue the RSE methodology. Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order. Under RSE, the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, whether Alagasco’s return on average equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. As of September 30, 2007, Alagasco had a $3.6 million pre-tax reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. Under the provisions of RSE, corresponding reductions in rates were effective October 1, 2007 and December 1, 2007. A $12 million and $14.3 million annual increase in revenues became effective December 1, 2007 and 2006, respectively.

Prior to the December 21, 2007 extension, RSE limited the utility’s equity upon which a return is permitted to 60 percent of total capitalization. Subsequent to the extension, the equity on which a return will be permitted will be phased down to 57 percent by September 30, 2008 and 55 percent by September 30, 2009.

Prior to the extension, under the inflation-based Cost Control Measurement (CCM) established by the APSC, if the percentage change in operations and maintenance (O&M) expense per customer fell within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (Index Range), no adjustment was required. If the change in O&M expense per customer exceeded the Index Range, three-quarters of the difference was returned to customers. To the extent the change was less than the Index Range, the utility benefited by one-half of the difference through future rate adjustments. The changes to the O&M expense CCM resulting from the December 21, 2007 extension are as follows: annual changes in O&M expense will be measured on an aggregate basis rather than per customer; the percentage change in O&M expense must fall within an Index Range of 0.75 points above or below the percentage change in the Consumer Price Index for All Urban Consumers; certain items that fluctuate based on situations demonstrated to be beyond Alagasco’s control may be excluded from

11

the CCM calculation; the O&M expense base for measurement purposes will continue to 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. Alagasco’s O&M expense fell within the Index Range for the rate year ended September 30, 2007.

Alagasco calculates a temperature adjustment to customers’ monthly bills to moderate the impact of departures from normal temperatures on Alagasco’s earnings. Adjustments to customers’ bills are made in the same billing cycle in which the weather variation occurs. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. This adjustment, however, is subject to regulatory limitations on increases to customers’ bills. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment such as the impact of wind velocity or cloud cover and the elasticity of demand as a result of higher commodity prices. 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.

3. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, 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 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. In some contracts, the amount of credit allowed before collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. At June 30, 2008, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net loss position with all of its counterparties at June 30, 2008. The Company believes the creditworthiness of these counterparties is satisfactory.

Energen Resources applies SFAS No. 133 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. Counterparty credit risk and nonperformance risk are considered in the evaluation of the effectiveness of a hedge and in the on-going qualification for hedge accounting treatment. 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. All derivative transactions are included in operating activities on the consolidated condensed statement of cash flows.

As of June 30, 2008, $263.6 million, net of tax, of deferred net losses 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. Gains and losses on derivative instruments that are not accounted for as cash flow hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. For the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, Energen Resources recorded a $0.5 million after-tax loss for the three months ended June 30, 2008, and a $1.5 million after-tax loss year-to date. Also, the Company recorded an after-tax loss of approximately $1.3 million during the second quarter of 2008 and a $1.9 million after-tax loss year-to-date on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of June 30, 2008, the Company had 0.59 billion cubic feet (Bcf) of gas 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 viable economic hedges.

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Energen Resources entered into the following transactions for the remainder of 2008 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2008	14.9 Bcf	$8.52 Mcf	NYMEX Swaps
	10.4 Bcf	$7.48 Mcf	Basin Specific Swaps
2009	14.2 Bcf	$8.55 Mcf	NYMEX Swaps
	29.6 Bcf	$7.76 Mcf	Basin Specific Swaps
2010	10.8 Bcf	$9.28 Mcf	NYMEX Swaps
	25.8 Bcf	$8.16 Mcf	Basin Specific Swaps
Natural Gas Basis Differential
2008	5.7 Bcf	*	Basis Swaps
Oil
2008	1,640 MBbl	$70.95 Bbl	NYMEX Swaps
2009	2,700 MBbl	$72.93 Bbl	NYMEX Swaps
2010	2,160 MBbl	$97.60 Bbl	NYMEX Swaps
Oil Basis Differential
2008	1,289 MBbl	*	Basis Swaps
2009	2,136 MBbl	*	Basis Swaps
2010	1,440 MBbl	*	Basis Swaps
Natural Gas Liquids
2008	23.6 MMGal	$0.96 Gal	Liquids Swaps
2009	43.3 MMGal	$1.15 Gal	Liquids Swaps
*  Average contract prices are not meaningful due to the varying nature of each contract.

The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2010.

Effective January 1, 2008, the Company partially 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”. 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;
Level 2	–	Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date;
Level 3	–	Pricing that requires inputs that are both significant to the fair value measure and unobservable.

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 New York Mercantile Exchange (NYMEX) swaps. 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.

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

	June 30, 2008
(in thousands)	Level 2			Level 3			Total
Current liabilities	$	(324,407	)	$	(124,457	)	$	(448,864	)
Noncurrent liabilities		(203,771	)		(91,825	)		(295,596	)
Net liability recognized	$	(528,178	)	$	(216,282	)	$	(744,460	)

The Company had a net $273.8 million and a net $39.9 million deferred tax asset included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in OCI as of June 30, 2008 and December 31, 2007, respectively. The Company had $14 million of current gains recorded in accounts receivable at December 31, 2007. At June 30, 2008 and December 31, 2007, the Company also had $448.9 million and $79.9 million, respectively, of current losses recorded in accounts payable. The Company also had $295.6 million and $47.1 million at June 30, 2008 and December 31, 2007, respectively, of non-current losses recorded in deferred credits and other liabilities related to derivative contracts. Additionally, the Company had $2.4 million of non-current gains recorded in deferred charges and other on the consolidated balance sheets as of December 31, 2007.

The table below sets 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, 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	)

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,” at December 31, 2007, Alagasco recognized a $0.4 million loss as a liability in accounts payable with a corresponding current regulatory asset representing the fair value of derivatives. At June 30, 2008, Alagasco had no hedge positions.

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

(in thousands, except per share amounts)	Three months ended June 30, 2008					Three months ended June 30, 2007
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	66,878	71,585	$	0.93	$	67,903	71,592	$	0.95
Effect of dilutive securities
Performance share awards			184					340
Stock options			212					231
Non-vested restricted stock			74					86
Diluted EPS	$	66,878	72,055	$	0.93	$	67,903	72,249	$	0.94

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(in thousands, except per share amounts)	Six months ended June 30, 2008					Six months ended June 30, 2007
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	183,566	71,611	$	2.56	$	171,785	71,538	$	2.40
Effect of dilutive securities
Performance share awards			176					325
Stock options			198					210
Non-vested restricted stock			69					80
Diluted EPS	$	183,566	72,054	$	2.55	$	171,785	72,153	$	2.38

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, as their effect was non-dilutive. For the three months and six months ended June 30, 2007, the Company had 7,260 and 239,545 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)	2008			2007			2008			2007
Operating revenues from continuing operations
Oil and gas operations	$	231,780		$	203,356		$	456,675		$	397,389
Natural gas distribution		109,486			111,566			406,237			410,194
Total	$	341,266		$	314,922		$	862,912		$	807,583
Operating income (loss) from continuing operations
Oil and gas operations	$	119,087		$	111,472		$	240,582		$	216,773
Natural gas distribution		(1,472	)		4,970			73,016			73,407
Eliminations and corporate expenses		(682	)		(537	)		(1,326	)		(1,077	)
Total	$	116,933		$	115,905		$	312,272		$	289,103
Other income (expense)
Oil and gas operations	$	(6,964	)	$	(8,335	)	$	(14,162	)	$	(15,839	)
Natural gas distribution		(3,263	)		(2,960	)		(7,523	)		(6,995	)
Eliminations and other		3			42			(13	)		(274	)
Total	$	(10,224	)	$	(11,253	)	$	(21,698	)	$	(23,108	)
Income from continuing operations before income taxes	$	106,709		$	104,652		$	290,574		$	265,995
(in thousands)	June 30, 2008						December 31, 2007
Identifiable assets
Oil and gas operations				$	2,336,096					$	2,065,229
Natural gas distribution					914,677						980,813
Subtotal					3,250,773						3,046,042
Eliminations and other					33,936						33,611
Total				$	3,284,709					$	3,079,653

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6. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended June 30,
(in thousands)	2008			2007
Net income	$	66,878		$	67,903
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($202.9) million and $7.5 million		(331,094	)		12,233
Reclassification adjustment for derivative instruments, net of tax of $28.6 million and ($6.9) million		46,623			(11,282	)
Pension and postretirement plans, net of tax of $0.3 million and $0.3 million		516			640
Comprehensive income (loss)	$	(217,077	)	$	69,494
	Six months ended June 30,
(in thousands)	2008			2007
Net income	$	183,566		$	171,785
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($271.7) million and ($12.7) million		(443,263	)		(20,750	)
Reclassification adjustment for derivative instruments, net of tax of $37.7 million and ($17.4) million		61,569			(28,392	)
Pension and postretirement plans, net of tax of $0.6 million and $1.3 million		1,031			2,499
Comprehensive income (loss)	$	(197,097	)	$	125,142
Accumulated other comprehensive income (loss) consisted of the following:
(in thousands)	June 30, 2008			December 31, 2007
Unrealized loss on hedges, net of tax of ($273.8) million and ($39.9) million	$	(446,750	)	$	(65,057	)
Pension and postretirement plans, net of tax of ($10.8) million and ($11.4) million		(20,137	)		(21,167	)
Accumulated other comprehensive loss	$	(466,887	)	$	(86,224	)

7. STOCK COMPENSATION

1997 Stock Incentive Plan

Stock Options: 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 186,700 non-qualified option shares during the first quarter of 2008 with a grant-date fair value of $17.83.

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 67,093 awards during the 2008 year-to-date. These awards had a fair value of $29.41 as of June 30, 2008.

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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. During the six months ended June 30, 2008, Energen Resources awarded 1,805 Petrotech units with a two year vesting period and a fair value of $77.32 as of June 30, 2008. During the year-to-date, Energen Resources also awarded 1,014 Petrotech units with a three year vesting period and a fair value of $76.84 as of June 30, 2008.

1997 Deferred Compensation Plan

During the three months and six months ended June 30, 2008, the Company had noncash purchases of approximately $31,000 and $27 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)”. Periodic expense is calculated on an actuarial basis and the net funded status of benefit plans is recognized as an asset or liability in its statement of financial position with changes in the funded status recognized through comprehensive income. For pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. Alagasco recognizes a regulatory asset for the portion of the obligation to be recovered in rates in future periods and a regulatory liability for the portion of the plan obligation to be provided through rates in the future in accordance with SFAS No. 71. 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 currently uses a September 30 valuation date for its benefit plans and anticipates adopting the change in measurement date using the alternative method. During the fourth quarter of 2008, the Company expects a one-time reduction to retained earnings and an adjustment to the regulatory assets and liabilities of Alagasco totaling approximately $3.3 million pre-tax in the transition to a December 31 valuation date.

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)	2008			2007			2008			2007
Components of net periodic benefit cost:
Service cost	$	1,790		$	1,703		$	3,580		$	3,406
Interest cost		2,950			2,771			5,900			5,565
Expected long-term return on assets		(3,289	)		(3,267	)		(6,578	)		(6,535	)
Actuarial loss		1,071			1,145			2,142			2,368
Prior service cost amortization		230			229			460			459
Settlement charge		-			-			-			2,124
Net periodic expense	$	2,752		$	2,581		$	5,504		$	7,387

The Company recognized settlement charges of $2.1 million during the first quarter of 2007 for the payment of lump sums from the nonqualified supplemental retirement plans. The Company is not required to make pension contributions in 2008 but currently plans on making discretionary contributions of approximately $11 million through year-end. For the three months and six months ended June 30, 2008, the Company made benefit payments aggregating $50,000 and $0.3 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $2.9 million through the remainder of 2008.

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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)	2008			2007			2008			2007
Components of net periodic benefit cost:
Service cost	$	409		$	256		$	818		$	511
Interest cost		1,229			923			2,458			1,846
Expected long-term return on assets		(1,384	)		(1,250	)		(2,768	)		(2,501	)
Actuarial gain		(195	)		(315	)		(390	)		(630	)
Transition amortization		479			479			959			959
Net periodic expense	$	538		$	93		$	1,077		$	185

For the three months and six months ended June 30, 2008, the Company made contributions aggregating $1 million and $1.2 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $1.4 million to postretirement benefit plan assets through the remainder of 2008.

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 $147 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 114 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, 2008, the fixed price purchases under these guarantees had a maximum term outstanding through February 2009 and an aggregate purchase price of $3.5 million with a market value of $5.1 million.

During 2007, Energen Resources entered into an agreement through March 2009 to secure a drilling rig necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of the drilling rig, Energen Resources’ total resulting exposure could be up to approximately $5 million depending on the contractors ability to remarket the drilling rig.

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.

Jefferson County, Alabama

In January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources’ calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. RGGS seeks a declaratory judgment with respect to the parties’ rights under the lease, reformation of the lease, monetary damages and termination of Energen Resources’ rights under the lease. The Occluded Gas Lease dated January 1, 1986 was originally between Energen Resources and United States Steel Corporation (U.S. Steel) as lessor. RGGS became the lessor under the

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lease as a result of a 2004 conveyance from U.S. Steel to RGGS. Approximately 120,000 acres in Jefferson and Tuscaloosa counties, Alabama, are subject to the lease. Separately on February 6, 2006, Energen Resources received notice of immediate lease termination from RGGS. During 2007, Energen Resources’ production associated with the lease was approximately 10.5 Bcf.

RGGS has adopted positions contrary to the seventeen years of course of dealing between Energen Resources and its original contracting partner, U.S. Steel. The Company believes that RGGS’ assertions are without merit and that the notice of lease termination is ineffective. Energen Resources intends to vigorously defend its rights under the lease. The Company remains in possession of the lease, believes that the likelihood of a judgment in favor of RGGS is remote and has made no material accrual with respect to the litigation or purported lease termination.

Legacy Litigation

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

Other

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

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

Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated.

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). An investigation of the sites does not indicate the present need for remediation activities. 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.

10. REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	June 30, 2008				December 31, 2007
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension asset	$	-	$	20,353	$	-	$	21,160
Accretion and depreciation for asset retirement obligation		-		11,553		-		11,024
Gas supply adjustment		3,674		-		9,711		-
Risk management activities		-		-		376		-
Other		43		34		145		54
Total regulatory assets	$	3,717	$	31,940	$	10,232	$	32,238
Regulatory liabilities:
Enhanced stability reserve	$	3,951	$	-	$	3,951	$	-
RSE adjustment		652		-		3,445		-
Unbilled service margin		7,093		-		24,725		-
Asset removal costs, net		-		126,860		-		121,573
Asset retirement obligation		-		14,791		-		14,367
Pension liability and postretirement benefits, net		-		4,966		-		4,188
Other		33		947		33		995
Total regulatory liabilities	$	11,729	$	147,564	$	32,154	$	141,123

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11. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

During the six months ended June 30, 2008, Energen Resources capitalized approximately $15.5 million of unproved leaseholds costs, approximately $11.2 million of which was related to the Company’s acreage position in Alabama shale. 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.

In May 2007, Energen Resources purchased oil properties in the Permian Basin for $18 million. To finance the acquisition, Energen used its available cash and existing lines of credit.

12. LONG-TERM DEBT

In May 2007, Energen voluntarily called $100 million Floating Rate Senior Notes due November 15, 2007. In April 2007, Energen voluntarily redeemed $10 million of Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026. Associated with this redemption, the Company incurred a call premium of 4.045%.

In January 2007, Alagasco issued $45 million of long-term debt with an interest rate of 5.9% due January 15, 2037. Alagasco used these long-term debt proceeds to redeem the $34.4 million of 6.75% Notes, maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026.

13. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD

The Company partially adopted the provisions of SFAS No. 157 as of January 1, 2008. SFAS No. 157 defines fair value, establishes criteria to be considered when measuring fair value and expands disclosures about fair value measurements. The additional disclosures for recurring financial instruments required under the standard are included in Note 3, Derivative Commodity Instruments.

In February 2008, the FASB issued FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157,” which delays the effective date of SFAS No. 157 for nonfinancial assets and liabilities except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. This FSP defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for those items within the scope of FSP 157-2. The deferred disclosures primarily relate to the Company’s asset retirement obligations.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to measure financial instruments and certain other items at fair value to mitigate volatility in reported earnings. This Statement is effective for fiscal years beginning after November 15, 2007. The Company has not elected the fair value option for any of its assets or liabilities and, therefore, implementation of this standard did not have a material impact on the consolidated financial position and results of operations.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations,” which is intended to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity

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provides in its financial reports about a business combination. This Statement applies prospectively to business combinations occurring in the fiscal year beginning on or after December 15, 2008. The Company is currently evaluating the impact of this Statement.

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. The effect of this Standard on the Company is currently being evaluated.

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 effect of this Standard on the Company is currently being evaluated.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. This Statement is effective 60 days following certain approvals by the Securities and Exchange Commission. The effect of this Standard on the Company is currently being evaluated.

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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 $66.9 million ($0.93 per diluted share) for the three months ended June 30, 2008 compared with net income of $67.9 million ($0.94 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, 2008, of $70.6 million as compared with $66.9 million in the same quarter in the previous year. Significantly higher commodity prices (approximately $12 million after-tax) and increased oil and gas production volumes (approximately $5 million after-tax) were partially offset by higher production taxes (approximately $5 million after-tax), increased depreciation, depletion and amortization (DD&A) expense (approximately $3 million after-tax), higher exploration expense (approximately $2 million after-tax) and increased lease operating expenses (approximately $1.5 million after-tax). Energen’s natural gas utility, Alagasco, reported a net loss of $3.1 million in the second quarter of 2008 compared to net income of $1.4 million in the same period last year. This deficit was affected primarily by the timing differences associated with rate recovery under Alagasco’s rate mechanism (approximately $2.4 million after-tax) and a decline in customer usage and other (approximately $2 million after-tax).

For the 2008 year-to-date, Energen’s net income totaled $183.6 million ($2.55 per diluted share) and compared favorably to net income of $171.8 million ($2.38 per diluted share) for the same period in the prior year. Energen Resources generated net income for the six months ended June 30, 2008, of $143.1 million as compared with $130.1 million in the previous period primarily as a result of higher commodity prices (approximately $21 million after-tax), increased production volumes (approximately $9 million after-tax), a $6.4 million after-tax gain on the sale of certain Permian Basin oil properties partially offset by the impact of higher production taxes (approximately $8 million after-tax), increased lease operating expenses (approximately $6 million after-tax), higher DD&A expense (approximately $5 million after-tax) and the decreased benefit from the Section 199 production activities deduction (approximately $2 million after-tax). Alagasco’s net income of $40.6 million in the current year-to-date compared to net income of $41.7 million in the same period in the previous year largely reflecting the utility’s ability to earn on a higher level of equity and lower operations and maintenance (O&M) expense of approximately $1.4 million after-tax. These items were more than offset by a decrease in customer usage and other (approximately $2.9 million after-tax) and timing differences associated with rate recovery.

Oil and Gas Operations

Revenues from oil and gas operations rose 14 percent to $231.8 million for the three months ended June 30, 2008 and 14.9 percent to $456.7 million in the year-to-date largely as a result of increased commodity prices as well as the impact of higher production volumes. During the current quarter, revenue per unit of production for natural gas rose 3.8 percent to $8.25 per thousand cubic feet (Mcf), while oil revenue per unit of production increased 16.4 percent to $74.51 per barrel. Natural gas liquids revenue per unit of production increased 27.6 percent to an average price of $1.11 per gallon. In the year-to-date, revenue per unit of production for natural gas increased 2.1 percent to $8.11 per Mcf, oil revenue per unit of production increased 16.5 percent to $71.31 per barrel and natural gas liquids revenue per unit of production rose 30.1 percent to an average price of $1.08 per gallon.

The Company recorded an after-tax loss of approximately $1.3 million during the second quarter of 2008 and a $1.9 million after-tax loss year-to-date on contracts which did not meet the definition of cash flow hedges under Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” For the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, Energen Resources recorded a $0.5 million after-tax loss for the three months ended June 30, 2008, and a $1.5 million after-tax loss year-to date.

Production increased primarily due to additional development activities in the San Juan, Permian and North Louisiana/East Texas basins partially offset by normal production declines and other. Natural gas production from continuing operations in the first quarter rose 4.5 percent to 16.4 billion cubic feet (Bcf), oil volumes increased 6.2 percent to 1,006 thousand barrels (MBbl) and natural gas liquids production decreased 5.2 percent to 18.1 million gallons (MMgal). For the year-to-date, natural gas production from continuing operations increased 5.1 percent to 32.8 Bcf, while oil volumes rose 4.1 percent to 1,950 MBbl. Natural gas liquids production decreased 8.2 percent to 34.9 MMgal due to normal production declines and severe winter weather in the San Juan Basin. Natural gas comprised approximately 65 percent of Energen Resources’ production for the current quarter and the year-to-date.

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Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. 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. Energen Resources recorded a pre-tax gain of $14,000 and a pre-tax gain of $130,000 in the three months and six months ended June 30, 2007, respectively, on the sale of various properties.

O&M expense increased $7.8 million for the quarter and $13.9 million in the year-to-date. Lease operating expense (excluding production taxes) increased by $2.5 million for the quarter largely due to higher transportation costs related to increased San Juan Basin production (approximately $0.9 million), increased repairs and maintenance expense in the San Juan Basin (approximately $0.8 million), higher workover expense (approximately $0.5 million),and increased environmental compliance expense (approximately $0.4 million). In the year-to-date, lease operating expense (excluding production taxes) rose $10.2 million primarily due to additional compression costs (approximately $2.4 million), higher workover expense (approximately $1.8 million), higher transportation costs related to increased San Juan Basin production (approximately $1.6 million), increased repairs and maintenance expense in the San Juan Basin (approximately $1.5 million), higher labor costs (approximately $1 million), increased electricity costs (approximately $0.9 million) and increased environmental compliance expense (approximately $0.7 million) partially offset by lower ad valorem taxes (approximately $0.9 million). Administrative expense increased $2.5 million and $0.6 million for the three months and six months ended June 30, 2008, respectively, largely due to higher labor-related expenses. The first quarter of 2007 included a settlement charge for the nonqualified supplemental retirement plan of approximately $1.1 million. Exploration expense rose $2.8 million in the second quarter of 2008 and $3 million in the year-to-date primarily due to mechanical difficulties encountered while drilling an exploratory well in the San Juan Basin.

Energen Resources’ DD&A expense for the quarter rose $5 million and increased $8.9 million year-to-date. The average DD&A rate for the current quarter was $1.25 per thousand cubic feet equivalent (Mcfe) as compared to $1.09 per Mcfe in the same period a year ago. For the six months ended June 30, 2008, the average depletion rate was $1.23 per Mcfe as compared to $1.09 per Mcfe in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $3.7 million and $6.9 million, respectively, was largely due to higher rates resulting from an increase in development costs. Increased production volumes also contributed approximately $1.2 million and $1.8 million to the increase in DD&A expense in the three months and six months ended June 30, 2008, respectively.

Energen Resources’ expense for taxes other than income taxes was $8 million and $12.5 million higher in the three months and six months ended June 30, 2008, respectively, largely due to production-related taxes. In the current quarter, higher oil, natural gas and natural gas liquid commodity market prices and the impact of increased production volumes contributed approximately $7.5 million and $0.5 million, respectively. Increased commodity market price and higher production volumes contributed approximately $11.7 million and $0.8 million, respectively, in the year-to-date. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues declined $2.1 million for the quarter largely due to a decrease in customer usage partially offset by an increase in gas costs. Weather that was 16.7 percent colder than in the same quarter in the prior year contributed to a slight increase in residential sales volumes largely offset by a decline in weather normalized customer usage. Commercial and industrial customer sales volumes remained stable while transportation volumes declined 7.6 percent in period comparisons. Revenues for the year-to-date declined $4 million largely due to a decrease in customer usage. For the year-to-date, weather was 6 percent colder compared to the same period last year. Residential sales volumes remained stable as the increase in temperature sensitive volumes were offset by a decline in weather normalized customer usage, while commercial and industrial customer sales volumes increased 1.6 percent. Transportation volumes also did not change in period comparisons. An increase in gas costs partially offset by a decrease in gas purchase volumes resulted in a 4.7 percent increase in cost of gas for the quarter. For the year-to-date, lower gas purchase volumes contributed to a 1.9 percent decrease in cost of gas. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price

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fluctuations to customers without markup. As discussed further in Future Capital Resources and Liquidity, a continued higher price commodity environment may result in significant increases in the GSA and further customer and usage declines. Alagasco’s tariff provides a temperature adjustment to certain customers’ bills 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.

As discussed more fully in Note 2, Regulatory Matters, in the Unaudited Condensed Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On December 21, 2007, the APSC issued an order to extend Alagasco’s rate-setting mechanism. Under the terms of that extension, RSE will continue after December 31, 2014, unless, after notice to Alagasco and a hearing, the APSC votes to either modify or discontinue the RSE methodology.

O&M expense rose 4.2 percent in the current quarter primarily due to increased consulting fees (approximately $0.8 million), increased labor-related costs (approximately $0.5 million) and higher distribution expenses (approximately $0.8 million). In the six months ended June 30, 2008, O&M expense decreased slightly. Decreased insurance costs (approximately $1.2 million), decreased bad expense (approximately $0.7 million) and lower labor-related costs (approximately $0.6 million) were largely offset by higher distribution expenses (approximately $1.1 million) and increased consulting fees (approximately $1 million). The first quarter of 2007 included a settlement charge for the nonqualified supplemental retirement plan of approximately $1 million. For the year ended December 31, 2008, O&M expense is expected to increase over the prior year by approximately 3 percent.

A 3.5 percent increase in depreciation expense in the current quarter and a 3.8 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 $1.8 million in the first quarter of 2008 and $2.9 million in the year-to-date largely due to the May 2007 voluntary call of the $100 million Floating Rate Senior Notes due November 15, 2007 along with lower short-term borrowings. Income tax expense for the Company increased $3.1 million in the current quarter and $12.8 million year-to-date largely due to higher pre-tax income along with the decreased benefit of the Section 199 deduction. The Section 199 deduction decreased $1.5 million and $2.4 million during the three months and six months ended June 30, 2008, respectively.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $315.4 million as compared to $284.4 million in the prior period. Operating cash flow benefited from higher realized commodity prices and production volumes at Energen Resources and a decrease in income taxes payable related to depreciation and basis differences from the prior period. The Company’s working capital needs were also influenced by commodity prices and the timing of payments. Negative working capital arising in large part from the current portion of cash flow hedges is expected to be offset as revenues are realized from production. Working capital needs at Alagasco were additionally affected by decreased storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $182.6 million for the six months ended June 30, 2008 primarily due to additions of property, plant and equipment. Energen Resources invested $172.9 million in capital expenditures primarily related to the development of oil and gas properties including approximately $15.5 million of unproved leaseholds, primarily shale related. During the year-to-date, Energen Resources received cash proceeds of $15.7 million primarily from the sale of certain Permian Basin oil properties. Utility capital expenditures totaled $28.6 million in the year-to-date and primarily represented expansion and replacement of its distribution system and support facilities.

The Company used $131.8 million for net financing activities in the year-to-date primarily for the repayment of short-term debt borrowings and the payment of dividends to common shareholders partially offset by the tax benefit on stock compensation.

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FUTURE CAPITAL RESOURCES AND LIQUIDITY

Oil and Gas Operations

Energen Resources has experienced various market driven conditions generally caused by the increased commodity price environment including, but not limited to, higher workover and maintenance expenses, increased taxes, higher 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 2008, the Company expects its oil and gas capital spending to total approximately $360 million, including $327 million for existing properties. The Company currently expects capital spending at Energen Resources to total approximately $271 million during 2009, including approximately $260 million for existing properties. The 2009 projection may be revised as Energen Resources completes its formal budgeting process in late 2008.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional accelerated development of existing properties and the exploration and further development of potential shale plays 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 property acquisitions is subject to market conditions and industry trends. Property acquisitions are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. In October 2006, Energen Resources and Chesapeake Energy Corporation (Chesapeake) signed an agreement to form an area of mutual interest (AMI) through which they will pursue new leases, exploration, development and operations on a 50-50 basis in an area which encompasses Alabama and some of Georgia, for at least the next 10 years. Energen Resources and Chesapeake continue to lease shared acreage in the AMI; as of June 30, 2008, Energen Resources had approximately $40 million of unproved leasehold costs related to its lease position in Alabama shale. Energen Resources’ net acreage position currently totals approximately 327,000 acres and represents multiple shale opportunities. During the first quarter of 2008, the Company initiated drilling activities for three wells as part of its well test program. Two of these wells are waiting on completion and the third well is nearing its total depth. Further testing must be completed before the Company can be certain whether one or more of these formations and concepts will be economically viable. The Company has not included in its capital spending estimates discussed above any amounts associated with exploratory drilling and/or future potential development for the Alabama shale position.

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.

Natural Gas Distribution

Since 2005, the higher price commodity environment has resulted in a decline in the utility’s customer base of approximately 1% annually and has the potential to produce continued adverse effects for the utility. Alagasco could have significant GSA increases in future periods. Sustained higher natural gas prices may further decrease Alagasco’s customer base and could result in a further decline in per customer use. 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. Further, during the six months ended June 30, 2008, Alagasco experienced a decline in usage by its construction industry related customers. Alagasco expects this usage decline to continue in the near term and currently anticipates utilizing its Enhanced Stability Reserve (ESR) of approximately $4 million during 2008. Absent the ESR reserve, projected earnings for 2008 would be lower by approximately $2.5 million. Under the provisions of the Rate Stabilization and Equalization rate-setting process, Alagasco’s rates in future periods will be adjusted to allow the utility to earn within its allowed range of return on average equity of 13.15 percent to 13.65 percent.

Alagasco maintains an investment in storage gas that is expected to average approximately $71 million in 2008 but

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will vary depending upon the price of natural gas. During 2008 and 2009, Alagasco plans to invest an estimated $66 million and $71 million, respectively, in utility capital expenditures for normal distribution and support systems. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. Alagasco also expects to receive a cash benefit in the year ended December 31, 2008 from an approximate $29 million tax refund from 2007 which resulted from an approved change 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 exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. Energen Resources applies SFAS No. 133 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 equity and subsequently reclassified into earnings 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. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in operating revenues in the period of change.

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 with a corresponding regulatory asset or liability in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”. Alagasco’s rate schedules for natural gas distribution charges contain a GSA rider which permits the pass-through to customers for changes in the cost of gas supply. The GSA rider is designed to capture the Company’s cost of natural gas and provides for a pass-through of gas cost fluctuations to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management gains and losses.

Energen Resources and Alagasco utilize derivative instruments which 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. In some contracts, the amount of credit allowed before collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. At June 30, 2008, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net loss position with all of its counterparties as of June 30, 2008. The Company believes the creditworthiness of these counterparties is satisfactory. These hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

Energen Resources entered into the following transactions for the remainder of 2008 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2008	14.9 Bcf	$8.52 Mcf	NYMEX Swaps
	10.4 Bcf	$7.48 Mcf	Basin Specific Swaps
2009	14.2 Bcf	$8.55 Mcf	NYMEX Swaps
	29.6 Bcf	$7.76 Mcf	Basin Specific Swaps
2010	10.8 Bcf	$9.28 Mcf	NYMEX Swaps
	25.8 Bcf	$8.16 Mcf	Basin Specific Swaps
Natural Gas Basis Differential
2008	5.7 Bcf	**	Basis Swaps
Oil
2008	1,640 MBbl	$70.95 Bbl	NYMEX Swaps
2009	2,700 MBbl	$72.93 Bbl	NYMEX Swaps
2010	2,160 MBbl	$97.60 Bbl	NYMEX Swaps
Oil Basis Differential
2008	1,289 MBbl	**	Basis Swaps
2009	2,136 MBbl	**	Basis Swaps
2010	1,440 MBbl	**	Basis Swaps
Natural Gas Liquids
2008	23.6 MMGal	$0.96 Gal	Liquids Swaps
2009	43.3 MMGal	$1.15 Gal	Liquids Swaps
**     Average contract prices are not meaningful due to the varying nature of each contract.

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

Effective January 1, 2008, the Company partially 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”. 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;
Level 2	–	Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date;
Level 3	–	Pricing that requires inputs that are both significant to the fair value measure and unobservable.

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 NYMEX swaps. 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 Company believes that these prices represent the best estimate of the exit price for these instruments as of the balance sheet date and are representative of the prices for which the contract will ultimately settle or realize.

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

	June 30, 2008
(in thousands)	Level 2			Level 3			Total
Current liabilities	$	(324,407	)	$	(124,457	)	$	(448,864	)
Noncurrent liabilities		(203,771	)		(91,825	)		(295,596	)
Net liability recognized	$	(528,178	)	$	(216,282	)	$	(744,460	)

Level 3 liabilities as of June 30, 2008 represent approximately 10 percent of total liabilities. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodities prices would result in a $73.6 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. 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

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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, 2008 and 2007. Currently, the Company expects any future stock repurchases to be funded through internally generated cash flow. During the six months ended June 30, 2008, the Company had noncash purchases of approximately $27 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

Short-Term Credit Facilities

Access to capital is an integral part of the Company’s business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. 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. On October 31, 2007, Standard & Poor’s affirmed its BBB+ corporate credit rating on Energen and Alagasco; the outlook remained stable. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets, continued access could be adversely affected by 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 aggregating $455 million of which Energen has available $285 million, Alagasco has available $100 million and $70 million is available to either Company.

Dividends

Energen expects to pay annual cash dividends of $0.48 per share on the Company’s common stock in 2008. 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, 2007.

Recent Pronouncements of the Financial Accounting Standards Board

The Company partially adopted the provisions of SFAS No. 157, “Fair Value Measurements,” as of January 1, 2008. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. The additional disclosures required under the standard are included in Note 3, Derivative Commodity Instruments.

In February 2008, the FASB issued FASB Staff Position (FSP) 157-2, “Effective Date of FASB Statement No. 157,” which delays the effective date of SFAS No. 157 for nonfinancial assets and liabilities except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. This FSP defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for those items within the scope of FSP 157-2. The deferred disclosures primarily relate to the Company’s asset retirement obligations.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to measure financial instruments and certain other items at fair value to mitigate volatility in reported earnings. This Statement is effective for fiscal years beginning after November 15, 2007. The Company has not elected the fair value option for any of its assets or liabilities and, therefore, implementation of this standard did not have a material impact on the consolidated financial position and results of operations.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), “Business Combinations,” which is intended to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination. This Statement applies prospectively to business combinations occurring in the fiscal year beginning on or after December 15, 2008. The Company is currently evaluating the impact of this Statement.

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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. The effect of this Standard on the Company is currently being evaluated.

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 effect of this Standard on the Company is currently being evaluated.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. This Statement is effective 60 days following certain approvals by the Securities and Exchange Commission. The effect of this Standard on the Company is currently being evaluated.

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 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.

Third Party Facilities: The forward-looking statements also assume generally uninterrupted access to third party oil, gas and natural gas liquid 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 Alagasco, Energen Resources and/or 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 acquisition, development and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors. Anticipated drilling plans and capital expenditures may also change due to weather, manpower and equipment availability, changing emphasis by management and a variety of other factors which could result in actual drilling and capital expenditures being substantially different than currently planned.

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Energen Resources’ Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future commodity 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, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position.

Alagasco’s Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position.

Operations: Inherent in the oil and gas production activities of Energen Resources and the gas distribution activities of Alagasco 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. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and/or the Company’s financial position, results of operations and cash flows.

Alagasco’s Service Territory: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.

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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)	2008			2007		2008		2007
Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$	135,216		$	124,712	$	266,170	$	247,937
Oil		74,928			60,615		139,027		114,699
Natural gas liquids		20,065			16,548		37,511		31,590
Other		1,571			1,481		13,967		3,163
Total	$	231,780		$	203,356	$	456,675	$	397,389
Production volumes from continuing operations
Natural gas (MMcf)		16,396			15,690		32,823		31,237
Oil (MBbl)		1,006			947		1,950		1,873
Natural gas liquids (MMgal)		18.1			19.1		34.9		38.0
Production volumes from continuing operations (MMcfe)		25,022			24,099		49,505		47,905
Total production volumes (MMcfe)		25,022			24,099		49,505		47,904
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	8.25		$	7.95	$	8.11	$	7.94
Oil (barrel)	$	74.51		$	64.03	$	71.31	$	61.23
Natural gas liquids (gallon)	$	1.11		$	0.87	$	1.08	$	0.83
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)	$	8.37		$	7.95	$	8.17	$	7.93
Oil (barrel)	$	74.50		$	63.62	$	71.83	$	61.02
Natural gas liquids (gallon)	$	1.11		$	0.87	$	1.08	$	0.83
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	9.90		$	7.01	$	8.85	$	6.79
Oil (barrel)	$	118.27		$	59.34	$	105.95	$	56.10
Natural gas liquids (gallon)	$	1.44		$	0.91	$	1.36	$	0.83
Other data from continuing operations
Lease operating expense (LOE)
LOE and other	$	41,602		$	39,121	$	84,737	$	74,530
Production taxes		21,553			13,589		38,129		25,600
Total	$	63,155		$	52,710	$	122,866	$	100,130
Depreciation, depletion and amortization	$	31,995		$	27,000	$	62,391	$	53,473
Capital expenditures	$	98,513		$	107,126	$	172,910	$	160,521
Exploration expenditures	$	2,960		$	178	$	3,309	$	275
Operating income	$	119,087		$	111,472	$	240,582	$	216,773
Natural Gas Distribution
Operating revenues
Residential	$	63,711		$	66,828	$	263,286	$	270,626
Commercial and industrial		31,378			31,172		108,883		108,894
Transportation		11,506			11,367		27,009		25,934
Other		2,891			2,199		7,059		4,740
Total	$	109,486		$	111,566	$	406,237	$	410,194
Gas delivery volumes (MMcf)
Residential		3,211			3,187		14,742		14,766
Commercial and industrial		1,983			1,981		6,959		6,853
Transportation		11,264			12,197		25,561		25,617
Total		16,458			17,365		47,262		47,236
Other data
Depreciation and amortization	$	12,119		$	11,707	$	24,139	$	23,254
Capital expenditures	$	15,926		$	16,606	$	28,996	$	31,573
Operating income (loss)	$	(1,472	)	$	4,970	$	73,016	$	73,407

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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 have been deemed 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. In some contracts, the amount of credit allowed before Energen Resources and Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. 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. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2010.

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 the Unaudited Condensed Financial Statements for details related to the Company’s hedging activities.

The Company’s interest rate exposure as of June 30, 2008, 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 Programs**
April 1, 2008 through April 30, 2008	-			-	-	8,992,700
May 1, 2008 through May 31, 2008	-			-	-	8,992,700
June 1, 2008 through June 30, 2008	420	*	$	74.84	-	8,992,700
Total	420		$	74.84	-	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

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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 8, 2008	By	/s/ James T. McManus, II
		James T. McManus, II
		Chairman, Chief Executive Officer and
		President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation
August 8, 2008	By	/s/ Charles W. Porter, Jr.
		Charles W. Porter, Jr.
		Vice President, Chief Financial Officer and Treasurer of Energen Corporation and Alabama Gas Corporation
August 8, 2008	By	/s/ Paula H. Rushing
		Paula H. Rushing
		Vice President-Finance of Alabama Gas Corporation

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