Energen (EGN) 10-Q 2008 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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 November 3, 2008.

Energen Corporation	$0.01 par value	71,709,059 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 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	23
	Selected Business Segment Data of Energen Corporation	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	35
Item 4.	Controls and Procedures	36
	PART II: OTHER INFORMATION
Item 1A.	Risk Factors	37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 6.	Exhibits	37
SIGNATURES		38

2

PART I. FINANCIAL INFORMATION

ITEM  1.FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

ENERGEN CORPORATION

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
(in thousands, except per share data)	2008			2007			2008			2007
Operating Revenues
Oil and gas operations	$	247,753		$	208,423		$	704,428		$	605,812
Natural gas distribution		82,452			67,599			488,689			477,793
Total operating revenues		330,205			276,022			1,193,117			1,083,605
Operating Expenses
Cost of gas		35,901			31,088			253,159			252,584
Operations and maintenance		88,168			84,857			268,147			251,011
Depreciation, depletion and amortization		47,111			41,457			133,641			118,184
Taxes, other than income taxes		27,266			18,988			92,039			71,170
Accretion expense		1,081			1,000			3,181			2,921
Total operating expenses		199,527			177,390			750,167			695,870
Operating Income		130,678			98,632			442,950			387,735
Other Income (Expense)
Interest expense		(10,319	)		(11,418	)		(31,699	)		(35,655	)
Other income		725			885			1,455			2,396
Other expense		(2,009	)		(244	)		(3,057	)		(626	)
Total other expense		(11,603	)		(10,777	)		(33,301	)		(33,885	)
Income From Continuing Operations Before Income Taxes		119,075			87,855			409,649			353,850
Income tax expense		46,011			29,841			153,019			124,052
Income From Continuing Operations		73,064			58,014			256,630			229,798
Discontinued Operations, Net of Taxes
Income from discontinued operations		-			2			-			3
Gain on disposal of discontinued operations		-			18			-			18
Income From Discontinued Operations		-			20			-			21
Net Income	$	73,064		$	58,034		$	256,630		$	229,819
Diluted Earnings Per Average Common Share
Continuing operations	$	1.01		$	0.80		$	3.56		$	3.18
Discontinued operations		-			-			-			-
Net Income	$	1.01		$	0.80		$	3.56		$	3.18
Basic Earnings Per Average Common Share
Continuing operations	$	1.02		$	0.81		$	3.58		$	3.21
Discontinued operations		-			-			-			-
Net Income	$	1.02		$	0.81		$	3.58		$	3.21
Dividends Per Common Share	$	0.12		$	0.115		$	0.36		$	0.345
Diluted Average Common Shares Outstanding		72,116			72,275			72,129			72,173
Basic Average Common Shares Outstanding		71,590			71,623			71,604			71,566

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

3

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

(in thousands)	September 30, 2008		December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents	$	11,947	$	8,687
Accounts receivable, net of allowance for doubtful accounts of $12,810 at September 30, 2008, and $12,244 at December 31, 2007		192,281		254,154
Inventories, at average cost
Storage gas inventory		94,029		78,064
Materials and supplies		10,991		13,711
Liquified natural gas in storage		3,156		3,502
Regulatory asset		35,589		10,232
Deferred income taxes		42,087		54,166
Prepayments and other		30,739		26,514
Total current assets		420,819		449,030
Property, Plant and Equipment
Oil and gas properties, successful efforts method		2,807,066		2,530,049
Less accumulated depreciation, depletion and amortization		752,553		664,290
Oil and gas properties, net		2,054,513		1,865,759
Utility plant		1,148,434		1,108,392
Less accumulated depreciation		469,181		448,053
Utility plant, net		679,253		660,339
Other property, net		14,909		12,145
Total property, plant and equipment, net		2,748,675		2,538,243
Other Assets
Regulatory asset		44,586		32,238
Prepaid pension costs and postretirement assets		5,897		20,054
Deferred charges and other		37,520		40,088
Total other assets		88,003		92,380
TOTAL ASSETS	$	3,257,497	$	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)	September 30, 2008			December 31, 2007
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	-		$	10,000
Notes payable to banks		23,000			134,000
Accounts payable		235,536			259,836
Accrued taxes		7,287			40,857
Customers’ deposits		20,465			21,425
Amounts due customers		18,971			20,534
Accrued wages and benefits		22,815			25,410
Regulatory liability		5,725			32,154
Royalty payable		30,695			22,563
Other		41,740			39,451
Total current liabilities		406,234			606,230
Long-term debt		561,820			562,365
Deferred Credits and Other Liabilities
Asset retirement obligation		63,974			60,571
Pension liabilities		26,463			31,985
Regulatory liability		146,522			141,123
Long-term derivative instruments		16,612			47,093
Deferred income taxes		383,926			238,706
Other		14,635			12,922
Total deferred credits and other liabilities		652,132			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, 74,510,474 shares issued at September 30, 2008, and 74,190,786 shares issued at December 31, 2007		745			742
Premium on capital stock		455,996			434,999
Capital surplus		2,802			2,802
Retained earnings		1,350,483			1,119,816
Accumulated other comprehensive loss, net of tax
Unrealized losses on hedges		(30,411	)		(65,057	)
Pension and postretirement plans		(21,847	)		(21,167	)
Deferred compensation plan		3,433			16,121
Treasury stock, at cost; 2,995,253 shares at September 30, 2008, and 3,374,336 shares at December 31, 2007		(123,890	)		(109,598	)
Total shareholders’ equity		1,637,311			1,378,658
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	3,257,497		$	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)

Nine months ended September 30,(in thousands)	2008			2007
Operating Activities
Net income	$	256,630		$	229,819
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		133,641			118,184
Deferred income taxes		140,967			(2,153	)
Change in derivative fair value		(1,642	)		(1,079	)
Gain on sale of assets		(10,753	)		(368	)
Other, net		(2,018	)		10,085
Net change in:
Accounts receivable, net		42,640			104,218
Inventories		(12,899	)		(12,829	)
Accounts payable		(19,219	)		(80,636	)
Amounts due customers		(16,140	)		19,721
Accrued taxes		(33,406	)		7,470
Other current assets and liabilities		(24,339	)		(7,700	)
Net cash provided by operating activities		453,462			384,732
Investing Activities
Additions to property, plant and equipment		(317,861	)		(253,821	)
Acquisitions, net of cash acquired		(16,099	)		(40,324	)
Proceeds from sale of assets		16,216			1,058
Other, net		(1,939	)		(2,184	)
Net cash used in investing activities		(319,683	)		(295,271	)
Financing Activities
Payment of dividends on common stock		(25,963	)		(24,830	)
Issuance of common stock		208			1,503
Payment of long-term debt		(10,676	)		(155,109	)
Proceeds from issuance of long-term debt		-			45,000
Debt issuance costs		-			(494	)
Net change in short-term debt		(111,000	)		30,000
Tax benefit on stock compensation		16,912			5,870
Other		-			1,003
Net cash used in financing activities		(130,519	)		(97,057	)
Net change in cash and cash equivalents		3,260			(7,596	)
Cash and cash equivalents at beginning of period		8,687			10,307
Cash and Cash Equivalents at End of Period	$	11,947		$	2,711

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

6

CONDENSED STATEMENTS OF INCOME

ALABAMA GAS CORPORATION

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2008			2007			2008			2007
Operating Revenues	$	82,452		$	67,599		$	488,689		$	477,793
Operating Expenses
Cost of gas		35,901			31,088			253,159			252,584
Operations and maintenance		33,642			32,467			99,076			98,199
Depreciation and amortization		12,262			11,847			36,401			35,101
Income taxes
Current		(41,953	)		(12,963	)		(21,445	)		12,335
Deferred		37,917			6,596			42,321			6,003
Taxes, other than income taxes		6,538			5,870			32,928			32,175
Total operating expenses		84,307			74,905			442,440			436,397
Operating Income (Loss)		(1,855	)		(7,306	)		46,249			41,396
Other Income (Expense)
Allowance for funds used during construction		189			180			515			492
Other income		170			581			539			1,484
Other expense		(738	)		(244	)		(1,578	)		(594	)
Total other income (expense)		(379	)		517			(524	)		1,382
Interest Charges
Interest on long-term debt		2,989			2,963			8,976			8,956
Other interest expense		581			789			1,972			2,656
Total interest charges		3,570			3,752			10,948			11,612
Net Income (Loss)	$	(5,804	)	$	(10,541	)	$	34,777		$	31,166

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

7

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

(in thousands)	September 30, 2008			December 31, 2007
ASSETS
Property, Plant and Equipment
Utility plant	$	1,148,434		$	1,108,392
Less accumulated depreciation		469,181			448,053
Utility plant, net		679,253			660,339
Other property, net		153			157
Current Assets
Cash and cash equivalents		6,748			7,335
Accounts receivable
Gas		66,768			139,761
Other		10,621			6,336
Allowance for doubtful accounts		(12,000	)		(11,500	)
Inventories, at average cost
Storage gas inventory		94,029			78,064
Materials and supplies		4,168			3,866
Liquified natural gas in storage		3,156			3,502
Deferred income taxes		22,824			25,179
Regulatory asset		35,589			10,232
Prepayments and other		3,853			2,247
Total current assets		235,756			265,022
Other Assets
Regulatory asset		44,586			32,238
Prepaid pension costs and postretirement assets		4,007			15,831
Deferred charges and other		6,476			7,226
Total other assets		55,069			55,295
TOTAL ASSETS	$	970,231		$	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)	September 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 September 30, 2008 and December 31, 2007		20		20
Premium on capital stock		31,682		31,682
Capital surplus		2,802		2,802
Retained earnings		270,963		261,979
Total common shareholder’s equity		305,467		296,483
Long-term debt		207,791		208,467
Total capitalization		513,258		504,950
Current Liabilities
Notes payable to banks		23,000		62,000
Accounts payable		78,476		80,067
Affiliated companies		30,972		4,934
Accrued taxes		13,091		30,858
Customers’ deposits		20,465		21,425
Amounts due customers		18,971		20,534
Accrued wages and benefits		7,636		10,062
Regulatory liability		5,725		32,154
Other		9,630		10,417
Total current liabilities		207,966		272,451
Deferred Credits and Other Liabilities
Deferred income taxes		95,029		59,790
Regulatory liability		146,522		141,123
Other		7,456		2,499
Total deferred credits and other liabilities		249,007		203,412
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$	970,231	$	980,813

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

9

CONDENSED STATEMENTS OF CASH FLOWS

ALABAMA GAS CORPORATION

(Unaudited)

Nine months ended September 30,(in thousands)	2008			2007
Operating Activities
Net income	$	34,777		$	31,166
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		36,401			35,101
Deferred income taxes		42,321			6,003
Other, net		(2,037	)		1,277
Net change in:
Accounts receivable		49,978			77,469
Inventories		(15,921	)		(10,077	)
Accounts payable		(19,567	)		(69,232	)
Amounts due customers		(16,140	)		19,721
Accrued taxes		(17,603	)		(4,872	)
Other current assets and liabilities		(5,778	)		(3,417	)
Net cash provided by operating activities		86,431			83,139
Investing Activities
Additions to property, plant and equipment		(44,365	)		(45,031	)
Other, net		(3,222	)		(1,781	)
Net cash used in investing activities		(47,587	)		(46,812	)
Financing Activities
Dividends		(25,793	)		(24,645	)
Payment of long-term debt		(676	)		(45,109	)
Proceeds from issuance of long-term debt		-			45,000
Debt issuance costs		-			(494	)
Net advances from (to) affiliates		26,038			(15,189	)
Net change in short-term debt		(39,000	)		(4,000	)
Other		-			1,003
Net cash used in financing activities		(39,431	)		(43,434	)
Net change in cash and cash equivalents		(587	)		(7,107	)
Cash and cash equivalents at beginning of period		7,335			8,765
Cash and Cash Equivalents at End of Period	$	6,748		$	1,658

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. Alagasco did not have a reduction in rates related to the return on average equity for the rate year ended 2008. 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. At September 30, 2008, RSE limited the utility’s equity upon which a return is permitted to 57 percent of total capitalization. The equity upon which a return is permitted will be phased down to 55 percent by September 30, 2009.

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

11

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 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. In the rate year ended September 30, 2008, the increase in O&M expense was below the Index Range; as a result the utility benefited by $2.9 million pre-tax. Alagasco’s O&M expense fell within the Index Range for the rate year ended September 30, 2007.

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco calculates a temperature adjustment to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment such as the impact of wind velocity or cloud cover and the elasticity of demand as a result of higher commodity prices.

The APSC approved an Enhanced Stability Reserve (ESR) beginning October 1997, with an approved maximum funding level of $4 million pre-tax, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting fromforce majeure events such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco’s return on equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR in an amount of no more than $40,000 monthly until the maximum funding level is achieved. Under the terms of the 2007 RSE extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR. Due to revenue losses from market sensitive large commercial and industrial customers, Alagasco utilized the ESR of approximately $4 million pre-tax during the third quarter of 2008.

3. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, 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 September 30, 2008, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with two of its counterparties and in a net loss position with the remaining four at September 30, 2008. The Company is at risk for economic loss based upon the creditworthiness of its counterparties.

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 statements of cash flows.

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The following table details the fair values of risk management assets and liabilities by business segment on the balance sheets:

(in thousands)	September 30, 2008						December 31, 2007
	Oil and Gas Operations		Natural Gas Distribution		Total		Oil and Gas Operations		Natural Gas Distribution		Total
Derivative assets:
Accounts receivable	$	19,237	$	-	$	19,237	$	14,002	$	-	$	14,002
Deferred charges and other		6,412		-		6,412		2,428		-		2,428
Total derivative assets	$	25,649	$	-	$	25,649	$	16,430	$	-	$	16,430
Derivative liabilities:
Accounts payable	$	65,920	$	18,351	$	84,271	$	79,916	$	376	$	80,292
Deferred credits and other liabilities		16,612		-		16,612		47,093		-		47,093
Total derivative liabilities	$	82,532	$	18,351	$	100,883	$	127,009	$	376	$	127,385

The Company had a net $18.6 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 September 30, 2008 and December 31, 2007, respectively.

As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet with a corresponding regulatory asset or liability. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”.

As of September 30, 2008, $24.1 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 $1 million after-tax gain for the three months ended September 30, 2008, and a $0.5 million after-tax loss year-to-date. Also, the Company recorded an after-tax gain of approximately $1.7 million during the third quarter of 2008 and a $0.2 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 September 30, 2008, the Company had 0.3 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 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	7.4 Bcf	$8.52 Mcf	NYMEX Swaps
	5.2 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	2.8 Bcf	*	Basis Swaps
Oil
2008	826 MBbl	$71.17 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	652 MBbl	*	Basis Swaps
2009	2,136 MBbl	*	Basis Swaps
2010	1,440 MBbl	*	Basis Swaps
Natural Gas Liquids
2008	11.7 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 within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;
Level 3 –	Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The Company believes that the fair value measure represents assumptions that market value participants would assume in pricing the asset or liability.

Over-the-counter derivatives are valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of 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.

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

	September 30, 2008
(in thousands)	Level 2*		Level 3*		Total
Current assets	$	(10,952)	$	30,189	$	19,237
Noncurrent assets		(9,665)		16,077		6,412
Current liabilities		(83,444)		(827)		(84,271)
Noncurrent liabilities		(16,612)		-		(16,612)
Net derivative asset (liability)	$	(120,673)	$	45,439	$	(75,234)

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

Alagasco has $18.4 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities.

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

4. RECONCILIATION OF EARNINGS PER SHARE (EPS)

(in thousands, except per share amounts)	Three months ended September 30, 2008					Three months ended September 30, 2007
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	73,064	71,590	$	1.02	$	58,034	71,623	$	0.81
Effect of dilutive securities
Performance share awards			209					353
Stock options			227					211
Non-vested restricted stock			90					88
Diluted EPS	$	73,064	72,116	$	1.01	$	58,034	72,275	$	0.80

(in thousands, except per share amounts)	Nine months ended September 30, 2008					Nine months ended September 30, 2007
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS	$	256,630	71,604	$	3.58	$	229,819	71,566	$	3.21
Effect of dilutive securities
Performance share awards			202					334
Stock options			234					192
Non-vested restricted stock			89					81
Diluted EPS	$	256,630	72,129	$	3.56	$	229,819	72,173	$	3.18

For the three months and nine months ended September 30, 2008, the Company had no options that were excluded from the computation of diluted EPS. For the three months and nine months ended September 30, 2007, the Company had 7,260 options and 239,545 options, respectively, that were excluded from the computation of diluted EPS, as their effect was non-dilutive.

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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 September 30,						Nine months ended September 30,
(in thousands)	2008			2007			2008			2007
Operating revenues from continuing operations
Oil and gas operations	$	247,753		$	208,423		$	704,428		$	605,812
Natural gas distribution		82,452			67,599			488,689			477,793
Total	$	330,205		$	276,022		$	1,193,117		$	1,083,605
Operating income (loss) from continuing operations
Oil and gas operations	$	137,270		$	112,899		$	377,852		$	329,672
Natural gas distribution		(5,891	)		(13,673	)		67,125			59,734
Eliminations and corporate expenses		(701	)		(594	)		(2,027	)		(1,671	)
Total	$	130,678		$	98,632		$	442,950		$	387,735
Other income (expense)
Oil and gas operations	$	(7,672	)	$	(7,567	)	$	(21,834	)	$	(23,406	)
Natural gas distribution		(3,949	)		(3,235	)		(11,472	)		(10,230	)
Eliminations and other		18			25			5			(249	)
Total	$	(11,603	)	$	(10,777	)	$	(33,301	)	$	(33,885	)
Income from continuing operations before income taxes	$	119,075		$	87,855		$	409,649		$	353,850

(in thousands)	September 30, 2008		December 31, 2007
Identifiable assets
Oil and gas operations	$	2,260,533	$	2,065,229
Natural gas distribution		970,231		980,813
Subtotal		3,230,764		3,046,042
Eliminations and other		26,733		33,611
Total	$	3,257,497	$	3,079,653

6. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended September 30,
(in thousands)	2008			2007
Net income	$	73,064		$	58,034
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $232.3 million and $6.8 million		379,007			11,110
Reclassification adjustment for derivative instruments, net of tax of $22.9 million and ($7.9) million		37,333			(12,929	)
Pension and postretirement plans, net of tax of ($0.9) million and ($0.4) million		(1,710	)		(810	)
Comprehensive income	$	487,694		$	55,405
	Nine months ended September 30,
(in thousands)	2008			2007
Net income	$	256,630		$	229,819
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of ($39.4) million and ($5.9) million		(64,256	)		(9,640	)
Reclassification adjustment for derivative instruments, net of tax of $60.6 million and ($25.3) million		98,902			(41,321	)
Pension and postretirement plans, net of tax of ($0.4) million and $0.9 million		(680	)		1,689
Comprehensive income	$	290,596		$	180,547

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

(in thousands)	September 30, 2008			December 31, 2007
Unrealized loss on hedges, net of tax of ($18.6) million and ($39.9) million	$	(30,411	)	$	(65,057	)
Pension and postretirement plans, net of tax of ($11.8) million and ($11.4) million		(21,847	)		(21,167	)
Accumulated other comprehensive loss	$	(52,258	)	$	(86,224	)

7. STOCK COMPENSATION

1997 Stock Incentive Plan

The 1997 Stock Incentive Plan provided for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 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 $7.20 as of September 30, 2008.

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 nine months ended September 30, 2008, Energen Resources awarded 1,805 Petrotech units with a two year vesting period and a fair value of $44.69 as of September 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 $44.22 as of September 30, 2008.

1997 Deferred Compensation Plan

During the three months and nine months ended September 30, 2008, the Company had noncash purchases of approximately $24,000 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. During the fourth quarter of 2008, the Company will change the measurement date to December 31 using the alternative method, and expects a one-time reduction to retained earnings of $1.2 million pre-tax and an adjustment to the regulatory assets and liabilities of Alagasco totaling approximately $2.1 million pre-tax.

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2008			2007			2008			2007
Components of net periodic benefit cost:
Service cost	$	1,790		$	1,703		$	5,370		$	5,109
Interest cost		2,950			2,771			8,851			8,336
Expected long-term return on assets		(3,289	)		(3,267	)		(9,867	)		(9,802	)
Actuarial loss		1,071			1,145			3,212			3,512
Prior service cost amortization		230			229			689			688
Settlement charge		-			3,532			-			5,657
Net periodic expense	$	2,752		$	6,113		$	8,255		$	13,500

In August 2008, the Company made a discretionary contribution of $11 million to the assets of a defined benefit qualified pension plan. The Company is not required to make pension contributions in 2008 but currently plans on making additional discretionary contributions of approximately $15 million through year-end. For the three months and nine months ended September 30, 2008, the Company made benefit payments aggregating $2.8 and $3.2 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $50,000 through the remainder of 2008. The Company recognized a settlement charge of $0.3 million and $2.4 million in three months and nine months ended September 30, 2007, respectively, for the payment of lump sums from the nonqualified supplemental retirement plans. The Company also recognized a settlement charge of $3.2 million in the third quarter of 2007 for the payment of lump sums from a defined benefit pension plan. These charges represented an acceleration of the unamortized actuarial losses as required under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.”

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

	Three months ended September 30,						Nine months ended September 30,
(in thousands)	2008			2007			2008			2007
Components of net periodic benefit cost:
Service cost	$	409		$	256		$	1,228		$	767
Interest cost		1,229			923			3,685			2,769
Expected long-term return on assets		(1,384	)		(1,250	)		(4,150	)		(3,751	)
Actuarial gain		(195	)		(315	)		(586	)		(945	)
Transition amortization		479			479			1,438			1,438
Net periodic expense	$	538		$	93		$	1,615		$	278

For the three months and nine months ended September 30, 2008, the Company made contributions aggregating $0.7 million and $1.9 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $0.7 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 $131 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 115 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

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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 September 30, 2008, the fixed price purchases under these guarantees had a maximum term outstanding through December 2009 and an aggregate purchase price of $12.7 million with a market value of $10.6 million.

Energen Resources entered into agreements which expire at various dates through May 2009 to secure drilling rigs necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of the drilling rigs, Energen Resources’ total resulting exposure could be up to approximately $7.2 million depending on the contractor’s ability to remarket the drilling rigs.

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 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, remediation of the Huntsville, Alabama manufactured gas plant site discussed below, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

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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). Subject to the following paragraph discussing the Huntsville, Alabama manufactured gas plant site, an investigation of the sites does not indicate the present need for remediation activities and management expects that, should remediation of any such sites be required in the future, Alagasco’s share, if any, of such costs will not materially affect the financial position of Alagasco.

In October 2008, Alagasco received a request from the United States Environmental Protection Agency (EPA) for information pursuant to the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) Section 104(e) and Section 7007 of the Resource Conservation and Recovery Act in connection with a former manufactured gas plant site located in Huntsville, Alabama. The site along with the Huntsville gas distribution system was sold by Alagasco to the City of Huntsville in 1949. The Company is in the process of responding to the EPA information request. While Alagasco no longer owns the Huntsville site, the Company anticipates that the EPA will consider Alagasco a potentially responsible party under CERCLA. At this time, Alagasco cannot estimate the costs which may be incurred in connection with the site. With respect to such costs, Alagasco plans to pursue insurance recovery and to request APSC approval to recover uninsured amounts through future rates.

10. REGULATORY ASSETS AND LIABILITIES

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

(in thousands)	September 30, 2008				December 31, 2007
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension and postretirement assets	$	-	$	32,739	$	-	$	21,160
Accretion and depreciation for asset retirement obligation		-		11,818		-		11,024
Gas supply adjustment		14,308		-		9,711		-
Risk management activities		18,351		-		376		-
RSE adjustment		2,887		-		-		-
Other		43		29		145		54
Total regulatory assets	$	35,589	$	44,586	$	10,232	$	32,238
Regulatory liabilities:
Enhanced stability reserve	$	-	$	-	$	3,951	$	-
RSE adjustment		200		-		3,445		-
Unbilled service margin		5,492		-		24,725		-
Asset removal costs, net		-		129,455		-		121,573
Asset retirement obligation		-		15,003		-		14,367
Pension liability and postretirement benefits, net		-		1,141		-		4,188
Other		33		923		33		995
Total regulatory liabilities	$	5,725	$	146,522	$	32,154	$	141,123

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11. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

During the nine months ended September 30, 2008, Energen Resources capitalized approximately $16.7 million of unproved leaseholds costs, approximately $12.4 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 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

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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.

In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) No. 03-06-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in the calculation of EPS under the two-class method as described in SFAS No. 128, “Earnings per Share.” This FSP is effective for fiscal years and interim periods beginning after December 15, 2008. The Company does not anticipate this FSP to have a material impact on the consolidated financial statements or the results of operations.

In October 2008, the FASB issued FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in an inactive market. This FSP is effective upon issuance and did not have a material impact on the consolidated financial statements or the results of operations.

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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 $73.1 million ($1.01 per diluted share) for the three months ended September 30, 2008 compared with net income of $58 million ($0.80 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen’s oil and gas subsidiary, had net income for the three months ended September 30, 2008, of $79.6 million as compared with $69.3 million in the same quarter in the previous year. Significantly higher commodity prices (approximately $20 million after-tax) and increased oil and gas production volumes (approximately $4 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), increased lease operating expenses (approximately $3 million after-tax) and the decreased benefit from the Section 199 production activities deduction (approximately $3 million after-tax). Energen’s natural gas utility, Alagasco, reported a net loss of $5.8 million in the third quarter of 2008 compared to a net loss of $10.5 million in the same period last year due to the utilization of the Enhanced Stability Reserve (ESR) to compensate for industrial and commercial load loss (approximately $2.5 million after tax), the benefit from the increase in O&M expense being below its inflation-based cost control measure (approximately $1.8 million after-tax) and timing differences associated with rate recovery under other Alagasco rate mechanisms combined with the utility’s ability to earn on a higher level of equity (approximately $3.4 million after-tax) partially offset by a decline in customer usage and other (approximately $2.9 million after-tax).

For the 2008 year-to-date, Energen’s net income totaled $256.6 million ($3.56 per diluted share) and compared favorably to net income of $229.8 million ($3.18 per diluted share) for the same period in the prior year. Energen Resources generated net income for the nine months ended September 30, 2008 of $222.6 million as compared with $199.4 million in the previous period primarily as a result of higher commodity prices (approximately $41 million after-tax), increased production volumes (approximately $13 million after-tax), and a $6.4 million after-tax gain on the sale of certain Permian Basin oil properties. Negatively affecting net income was the impact of higher production taxes (approximately $13 million after-tax), increased lease operating expenses (approximately $10 million after-tax), higher DD&A expense (approximately $9 million after-tax) and the decreased benefit from the Section 199 deduction (approximately $5 million after-tax). Alagasco’s net income of $34.8 million increased in the current year-to-date compared to net income of $31.2 million in the same period in the previous year largely reflecting the utility’s ability to earn on a higher level of equity combined with timing differences associated with rate recovery (approximately $3.8 million after-tax), the charge against the ESR discussed above (approximately $2.5 million after-tax) and the benefit from the increase in O&M expense being below its inflation-based cost control measure (approximately $1.8 million after-tax). Negatively affecting net income was a decrease in customer usage and other (approximately $4.4 million after-tax).

Oil and Gas Operations

Revenues from oil and gas operations rose 18.9 percent to $247.8 million for the three months ended September 30, 2008 and 16.3 percent to $704.4 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 12.4 percent to $8.42 per thousand cubic feet (Mcf), while oil revenue per unit of production increased 20 percent to $78.08 per barrel. Natural gas liquids revenue per unit of production increased 15.7 percent to an average price of $1.03 per gallon. In the year-to-date, revenue per unit of production for natural gas increased 5.7 percent to $8.22 per Mcf, oil revenue per unit of production increased 17.8 percent to $73.69 per barrel and natural gas liquids revenue per unit of production rose 24.7 percent to an average price of $1.06 per gallon.

The Company recorded an after-tax gain of approximately $1.7 million during the third quarter of 2008 and a $0.2 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 $1 million after-tax gain for the three months ended September 30, 2008, and a $0.5 million after-tax loss year-to-date.

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Production for both the current quarter and year-to-date 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 third quarter rose 4.6 percent to 17.3 billion cubic feet (Bcf), oil volumes increased 2.9 percent to 1,055 thousand barrels (MBbl) and natural gas liquids production decreased 9.2 percent to 17.8 million gallons (MMgal). For the year-to-date, natural gas production from continuing operations increased 4.9 percent to 50.1 Bcf, while oil volumes rose 3.7 percent to 3,005 MBbl. Natural gas liquids production decreased 8.5 percent to 52.7 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.

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 third quarter of 2008, Energen Resources recorded a pre-tax gain of $54,000 and a pre-tax gain of $10.3 million in the year-to-date largely from the sale of certain Permian Basin oil properties. Energen Resources recorded a pre-tax gain of $28,000 and a pre-tax gain of $140,000 in the three months and nine months ended September 30, 2007, respectively, on the sale of various properties.

O&M expense increased $2 million for the quarter and $15.9 million in the year-to-date. Lease operating expense (excluding production taxes) increased by $5.2 million for the quarter largely due to higher workover expense (approximately $2.5 million), higher transportation costs related to increased San Juan Basin production (approximately $1.3 million), increased repairs and maintenance expense (approximately $1 million) and increased environmental compliance expense (approximately $0.4 million). In the year-to-date, lease operating expense (excluding production taxes) rose $15.4 million primarily due to higher workover expense (approximately $4.6 million), higher transportation costs (approximately $3.5 million), additional compression costs (approximately $2.5 million), increased repairs and maintenance expense (approximately $2.4 million), higher labor costs (approximately $1.1 million), increased electricity costs (approximately $0.7 million) and increased environmental compliance expense (approximately $0.6 million) partially offset by lower ad valorem taxes (approximately $1.5 million). Administrative expense decreased $2.7 million and $2 million for the three months and nine months ended September 30, 2008, respectively, largely due to lower benefit costs primarily related to the Company’s performance-based compensation plans. The first quarter of 2007 included a settlement charge for the nonqualified supplemental retirement plan of approximately $1.1 million. Exploration expense declined $0.5 million in the third quarter of 2008. In the year-to-date, exploration expense rose $2.5 million 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 $5.2 million and increased $14.2 million year-to-date. The average DD&A rate for the current quarter was $1.30 per thousand cubic feet equivalent (Mcfe) as compared to $1.14 per Mcfe in the same period a year ago. For the nine months ended September 30, 2008, the average depletion rate was $1.25 per Mcfe as compared to $1.11 per Mcfe in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $3.2 million and $9.4 million, respectively, was largely due to higher rates resulting from an increase in development costs. Increased production volumes also contributed approximately $1.9 million and $4.4 million to the increase in DD&A expense in the three months and nine months ended September 30, 2008, respectively.

Energen Resources’ expense for taxes other than income taxes was $7.6 million and $20.1 million higher in the three months and nine months ended September 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 $7.3 million and $0.4 million, respectively. Increased commodity market price and higher production volumes contributed approximately $19 million and $1.2 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 rose $14.9 million for the quarter largely related to adjustments from the utility’s rate setting mechanisms along with an increase in gas costs partially offset by a decline in customer usage. Alagasco charged approximately $4 million against the ESR during the third quarter of 2008 due to a decline in usage by

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market sensitive commercial and industrial customers. At the end of the 2008 rate year, the increase in O&M expense was below its inflation-based cost control measure; as a result the utility benefited by a $2.9 million pre-tax increase in revenues for the three months ended September 30, 2008. For the quarter ending September 30, 2007, Alagasco had a $3.6 million reduction in revenues to bring the return on average equity to midpoint in the allowed range of return. For the third quarter, weather was comparable with the same quarter in the period year. Residential sales volumes decreased 2.1 percent, commercial and industrial customer sales volumes decreased 8.6 percent while transportation volumes declined 16.2 percent in period comparisons. Revenues for the year-to-date increased $10.9 million primarily due to the adjustments for rate-setting purposes described above along with an increase in gas costs partially offset by a decrease in customer usage. For the nine months ended September 30, 2008, weather was 6 percent colder compared to the same period last year. Residential sales volumes remained stable as the increase in temperature sensitive volumes was offset by a decline in weather normalized customer usage. Commercial and industrial customer sales volumes remained stable while transportation volumes decreased 5.5 percent in period comparisons. An increase in gas costs combined with a slight rise in gas purchase volumes resulted in a 15.5 percent increase in cost of gas for the quarter. For the year-to-date, cost of gas increased slightly as higher gas costs were largely offset by lower gas purchase volumes. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. As discussed further in Future Capital Resources and Liquidity, a high price commodity environment may result in significant increases in the GSA and further customer and usage declines. Alagasco’s tariff provides a temperature adjustment 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 3.6 percent in the current quarter primarily due to increased bad debt expense (approximately $1.2 million) and higher consulting and technology fees (approximately $1.9 million) partially offset by decreased labor-related costs (approximately $1.9 million). In the nine months ended September 30, 2008, O&M expense increased slightly. Lower labor-related costs (approximately $2.5 million) and decreased insurance costs (approximately $0.9 million) were more than offset by increased consulting and technology fees (approximately $3 million) and higher distribution expenses (approximately $1 million). The three months and nine months ended September 30, 2007 included a settlement charge for the nonqualified supplemental retirement plan of approximately $1 million and $1.1 million, respectively. For the year ended December 31, 2008, O&M expense is expected to increase over the prior year by an approximate range of 2 percent to 4 percent.

A 3.5 percent increase in depreciation expense in the current quarter and a 3.7 percent increase in the year-to-date was primarily due to extension and replacement of the utility’s distribution system and replacement of its support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company decreased $1.1 million in the third quarter of 2008 largely due to lower borrowings at Energen Resources combined with lower interest rates on short-term borrowings. For the year-to-date, interest expense declined $4 million primarily due to the May 2007 voluntary call of the $100 million Floating Rate Senior Notes due November 15, 2007 along with lower interest rates on short-term borrowings. Income tax expense for the Company increased $16.2 million in the current quarter and $29 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 $3 million and $5.4 million during the three months and nine months ended September 30, 2008, respectively.

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FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $453.5 million as compared to $384.7 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, accrued taxes, the timing of payments and tax withholdings in conjunction with purchases of Company common stock on its non-qualified deferred compensation plan and other stock compensation. Working capital needs at Alagasco were additionally affected by increased storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $319.7 million for the nine months ended September 30, 2008 primarily due to additions of property, plant and equipment. Energen Resources invested $295.5 million in capital expenditures primarily related to the development of oil and gas properties including approximately $16.7 million of unproved leaseholds, primarily shale related. During the year-to-date, Energen Resources received cash proceeds of $16.2 million primarily from the sale of certain Permian Basin oil properties. Utility capital expenditures totaled $44.4 million in the year-to-date and primarily represented expansion and replacement of its distribution system and support facilities.

The Company used $130.5 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.

FUTURE CAPITAL RESOURCES AND LIQUIDITY

Recent Market Events

Capital and credit markets have and continue to experience extreme volatility and disruption. If such volatility and disruptions continue or worsen, the Company may experience material adverse effects upon its financial position, results of operations and cash flows. While such events did not have a material impact upon the Company’s current period, these events have the potential for a negative impact including, but not limited to, the following areas:

Risk Management: The Company utilizes derivative instruments to hedge its exposure to commodity price fluctuations. These derivative instruments are entered into with investment grade counterparties and are assessed each reporting period as to hedge effectiveness. Specifically, the Company considers the likelihood that the counterparty will be able to perform under the terms of the derivative instrument. If the Company is unable to conclude that it is probable that such counterparty will be able to perform under the terms of the derivative instrument, then the Company would be required to cease hedge accounting and recognize all gains and losses from that point forward in its results of operations. Further, the Company would then be at risk of nonperformance for any derivative contracts which are in a gain position. The Company’s current counterparties with active positions are Morgan Stanley, Goldman Sachs, Citigroup, Bank of Montreal, Merrill Lynch and Wachovia Corporation.

The Company also maintains insurance policies which protect against certain business risks. Associated with these policies the Company has recognized insurance receivables for losses incurred. If these receivables were adversely affected a loss would be recognized in the results of operations.

Access to Capital: The Company relies upon its excess cash flows supplemented by its short-term credit facilities to fund working capital needs. The Company currently has not experienced any disruption in the availability of its short-term credit facilities.

As detailed in the following table, the Company currently has available short-term credit facilities with seven investment grade financial institutions aggregating $515 million of which Energen has available $320 million, Alagasco has available $125 million and $70 million is available to either Company.

(in thousands)	Current Term	Energen		Alagasco		Total
Regions Bank	4/24/2009	$	145,000	$	55,000	$	200,000
Wachovia Bank, N.A.	12/15/2008		65,000		35,000		100,000
Compass Bank	8/6/2009		70,000		70,000		70,000
RBC Bank (USA)	10/21/2009		20,000		15,000		35,000
The Bank of New York Mellon	12/5/2008		50,000		-		50,000
Citicorp USA, Inc.	2/20/2009		25,000		10,000		35,000
The Northern Trust Company	10/14/2009		15,000		10,000		25,000
		$	390,000	$	195,000	$	515,000

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The above short-term credit facilities are 364-day committed bilateral agreements. Energen and Alagasco are subject to the risk that these facilities will not be renewed or will be renewed at less favorable terms. However, the Company believes that its expected cash flows, the diversity of credit facilities and its ability to adjust future capital spending provides adequate support for its liquidity needs.

Oil and Gas Operations

Energen Resources has not yet experienced a decline in various market driven costs despite the recently lower commodity price environment including, but not limited to, workover and maintenance expenses, ad valorem taxes, 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 $400 million, including $365 million for existing properties. The Company currently expects capital spending at Energen Resources to total approximately $295 million during 2009, including approximately $280 million for existing properties. The 2009 projection may be revised as Energen Resources completes its formal budgeting process and incorporates the effect of any commodity price changes through year-end.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional 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 signed an agreement to form an area of mutual interest 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. As of September 30, 2008, Energen Resources had approximately $41 million of unproved leasehold costs related to its lease position in Alabama shale. The Company has exposure to potential impairment of unproved leasehold associated with this lease position. Energen Resources’ net acreage position currently totals approximately 331,000 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. A completion has been performed on two wells and the third well is waiting on completion. Data from these wells must be analyzed before the Company can determine 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. The recently lower commodity price environment has not yet reversed this adverse trend at the utility. A return of natural gas prices to higher levels could result in a further decline in Alagasco’s customer base and usage and in significant increases in the utility’s GSA. 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

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natural gas prices. During the year-to-date September 30, 2008, Alagasco charged approximately $4 million against the ESR due to a decline in usage by its construction industry related customers. Alagasco expects this usage decline to continue in the near term. Absent the utilization of the ESR reserve, projected earnings for 2008 would be lower by approximately $2.5 million. Under the terms of the 2007 RSE extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three-year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR. 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 $68 million in 2008 but will vary depending upon the price of natural gas. During 2008 and 2009, Alagasco plans to invest an estimated $62 million and $65 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, 2009 from an approximate $27.6 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 September 30, 2008, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with two of its counterparties and in a net loss position with the remaining four at September 30, 2008. Subsequent to September 30, 2008, the Company has a net gain position with its active counterparties. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. These hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions.

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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	7.4 Bcf	$8.52 Mcf	NYMEX Swaps
	5.2 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	2.8 Bcf	**	Basis Swaps
Oil
2008	826 MBbl	$71.17 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	652 MBbl	**	Basis Swaps
2009	2,136 MBbl	**	Basis Swaps
2010	1,440 MBbl	**	Basis Swaps
Natural Gas Liquids
2008	11.7 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.

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 within Level 1, which are either directly or indirectly observable through correlation with market data as of the reporting date;
Level 3 –	Pricing that requires inputs that are both significant and unobservable to the calculation of the fair value measure. The Company believes that the fair value measure represents assumptions that market value participants would assume in pricing the asset or liability.

Over-the-counter derivatives are valued using market transactions and other market evidence whenever possible, including market-based inputs to models and broker or dealer quotations. These OTC derivative contracts trade in less liquid markets with limited pricing information as compared to markets with actively traded, unadjusted quoted prices; accordingly, the determination of fair value is inherently more difficult. OTC derivatives for which the Company is able to substantiate fair value through directly observable market prices are classified within Level 2 of the fair value hierarchy. These Level 2 fair values consist of 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. As of the balance sheet date, the Company believes that these prices represent the best estimate of the exit price for these instruments and are representative of the prices for which the contract will ultimately settle or realize.

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

	September 30, 2008
(in thousands)	Level 2*			Level 3*			Total
Current assets	$	(10,952	)	$	30,189		$	19,237
Noncurrent assets		(9,665	)		16,077			6,412
Current liabilities		(83,444	)		(827	)		(84,271	)
Noncurrent liabilities		(16,612	)		—			(16,612	)
Net derivative asset (liability)	$	(120,673	)	$	45,439		$	(75,234	)

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

Alagasco has $18.4 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current liabilities.

Level 3 assets and liabilities as of September 30, 2008 represent approximately 1 percent of total assets and an immaterial amount of total liabilities, respectively. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase in commodity prices would result in a $41.1 million change in the fair value of open Level 3 derivative contracts while a 10 percent decrease in commodity prices would result in a $40.2 million change in fair value. 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 market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. The Company did not repurchase shares of common stock for this program during the three months or nine months ended September 30, 2008 and 2007. The Company expects any future stock repurchases to be funded through internally generated cash flow or through the utilization of its short-term credit facilities. During the nine months ended September 30, 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. While the Company expects to have ongoing access to its short-term credit facilities and the longer-term markets, continued access could be adversely affected by current and future economic and business conditions and credit rating downgrades. To help finance its growth plans and operating needs, the Company currently has available short-term credit facilities with seven investment grade financial institutions aggregating $515 million of which Energen has available $320 million, Alagasco has available $125 million and $70 million is available to either Company.

The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations.

On October 15, 2008, Standard and Poor’s placed Energen and Alagasco under review with a negative outlook reflecting an evaluation of the business risk profile for the Company and not predicated on any near-term liquidity issues, poor financial performance, or concerns related to turmoil in the capital markets. The Company expects the review to be resolved within three months. Previously, on October 31, 2007, Standard & Poor’s affirmed its BBB+ corporate credit rating on Energen and Alagasco.

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

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assignment of increased risk exposure related to the growth of its oil and gas operations in contrast to its legacy natural gas distribution assets. Moody’s also confirmed the debt rating of Alagasco during this review as A1 senior unsecured.

Dividends

Energen expects to pay annual cash dividends of $0.48 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.

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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In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) No. 03-06-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and need to be included in the calculation of EPS under the two-class method as described in SFAS No. 128, “Earnings per Share.” This FSP is effective for fiscal years and interim periods beginning after December 15, 2008. The Company does not anticipate this FSP to have a material impact on the consolidated financial statements or the results of operations.

In October 2008, the FASB issued FSP 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in an inactive market. This FSP is effective upon issuance and did not have a material impact on the consolidated financial statements or the results of operations.

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.

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

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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 September 30,						Nine months ended September 30,
(in thousands, except sales price data)	2008			2007			2008		2007
Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$	145,283		$	123,499		$	411,453	$	371,436
Oil		82,375			66,689			221,402		181,388
Natural gas liquids		18,404			17,486			55,915		49,076
Other		1,691			749			15,658		3,912
Total	$	247,753		$	208,423		$	704,428	$	605,812
Production volumes from continuing operations
Natural gas (MMcf)		17,258			16,495			50,081		47,732
Oil (MBbl)		1,055			1,025			3,005		2,898
Natural gas liquids (MMgal)		17.8			19.6			52.7		57.6
Production volumes from continuing operations (MMcfe)		26,134			25,445			75,639		73,350
Total production volumes (MMcfe)		26,134			25,445			75,639		73,349
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	8.42		$	7.49		$	8.22	$	7.78
Oil (barrel)	$	78.08		$	65.06		$	73.69	$	62.58
Natural gas liquids (gallon)	$	1.03		$	0.89		$	1.06	$	0.85
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)	$	8.26		$	7.49		$	8.20	$	7.78
Oil (barrel)	$	78.09		$	65.06		$	74.02	$	62.45
Natural gas liquids (gallon)	$	1.03		$	0.89		$	1.06	$	0.85
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	9.03		$	5.82		$	8.91	$	6.45
Oil (barrel)	$	116.81		$	69.70		$	109.77	$	60.91
Natural gas liquids (gallon)	$	1.37		$	0.99		$	1.36	$	0.89
Other data from continuing operations
Lease operating expense (LOE)
LOE and other	$	43,890		$	38,706		$	128,627	$	113,236
Production taxes		20,610		$	12,968			58,739		38,568
Total	$	64,500		$	51,674		$	187,366	$	151,804
Depreciation, depletion and amortization	$	34,849		$	29,610		$	97,240	$	83,083
Capital expenditures	$	122,597		$	94,274		$	295,507	$	254,795
Exploration expenditures	$	906		$	1,396		$	4,215	$	1,671
Operating income	$	137,270		$	112,899		$	377,852	$	329,672
Natural Gas Distribution
Operating revenues
Residential	$	38,347		$	35,685		$	301,633	$	306,312
Commercial and industrial		24,121			21,384			133,004		130,279
Transportation		10,816			10,575			37,825		36,509
Other		9,168			(45	)		16,227		4,693
Total	$	82,452		$	67,599		$	488,689	$	477,793
Gas delivery volumes (MMcf)
Residential		1,505			1,537			16,247		16,303
Commercial and industrial		1,390			1,520			8,349		8,373
Transportation		10,706			12,779			36,267		38,396
Total		13,601			15,836			60,863		63,072
Other data
Depreciation and amortization	$	12,262		$	11,847		$	36,401	$	35,101
Capital expenditures	$	15,959		$	14,023		$	44,955	$	45,596
Operating income (loss)	$	(5,891	)	$	(13,673	)	$	67,125	$	59,734

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ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its gas supply exposure. Such instruments may include natural gas and crude oil over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. These counterparties are believed to be creditworthy by the Company and have agreed in certain instances to post collateral with the Company when unrealized gains on hedges exceed certain specified contractual amounts. Notwithstanding these agreements, the Company is at risk for economic loss based upon the creditworthiness of its counterparties. 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 September 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 1A.RISK FACTORS

Except for the items discussed below, there have been no material changes to the risks described in Part 1, Item 1A, Risk Factors in the 2007 Annual Report of Energen and Alagasco on Form 10-K.

Access to Credit Markets: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is influenced significantly by market events and rating agency evaluations for both the issuer and the Company. Recent market volatility and credit market disruption have demonstrated that credit quality can change rapidly, and events affecting credit market liquidity could increase borrowing costs or limit availability of funds.

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

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Progams**
July 1, 2008 through July 31, 2008	-			-	-	8,992,700
August 1, 2008 through August 31, 2008	-			-	-	8,992,700
September 1, 2008 through September 30, 2008	432	*	$	55.28	-	8,992,700
Total	432		$	55.28	-	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
November 7, 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
November 7, 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
November 7, 2008	By	/s/ Paula H. Rushing
		Paula H. Rushing
		Vice President-Finance of Alabama Gas
		Corporation

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