Alabama Gas Corporation, a wholly owned subsidiary of Energen Corporation, meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form with reduced disclosure format pursuant to General Instruction H(2).

Indicate by a check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YESx NO¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Act).

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

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of ~~May 1,~~October 30, 2007


	Three months ended March 31,						Three months ended September 30,						Nine months ended September 30,
*(in thousands, except per share data)*	2007			2006			2007			2006			2007			2006
Operating Revenues
Oil and gas operations	$	194,033		$	169,519		$	208,423		$	171,516		$	605,812		$	510,213
Natural gas distribution		298,628			318,623			67,599			71,195			477,793			503,014

Total operating revenues		492,661			488,142			276,022			242,711			1,083,605			1,013,227

Operating Expenses
Cost of gas		168,138			194,050			31,088			32,311			252,584			284,192
Operations and maintenance		82,043			74,483			84,857			78,836			251,011			231,720
Depreciation, depletion and amortization		38,020			34,297			41,457			35,676			118,184			104,472
Taxes, other than income taxes		30,312			32,679			18,988			19,338			71,170			73,450
Accretion expense		950			898			1,000			881			2,921			2,691

Total operating expenses		319,463			336,407			177,390			167,042			695,870			696,525

Operating Income		173,198			151,735			98,632			75,669			387,735			316,702

Other Income (Expense)
Interest expense		(12,221	)		(13,177	)		(11,418	)		(12,267	)		(35,655	)		(37,810	)
Other income		561			707			885			448			2,396			1,410
Other expense		(195	)		(229	)		(244	)		(207	)		(626	)		(708	)

Total other expense		(11,855	)		(12,699	)		(10,777	)		(12,026	)		(33,885	)		(37,108	)

Income From Continuing Operations Before Income Taxes		161,343			139,036			87,855			63,643			353,850			279,594
Income tax expense		57,462			51,535			29,841			22,346			124,052			101,194

Income From Continuing Operations		103,881			87,501			58,014			41,297			229,798			178,400

Discontinued Operations, Net of Taxes
Income (loss) from discontinued operations		1			(7	)		2			2			3			(6	)
Gain (loss) on disposal of discontinued operations		—			—
Gain on disposal of discontinued operations								18			53			18			53

Income (Loss) From Discontinued Operations		1			(7	)
Income From Discontinued Operations								20			55			21			47

Net Income	$	103,882		$	87,494		$	58,034		$	41,352		$	229,819		$	178,447

Diluted Earnings Per Average Common Share
Continuing operations	$	1.44		$	1.18		$	0.80		$	0.56		$	3.18		$	2.42
Discontinued operations		—			—			—			—			—			—

Net Income	$	1.44		$	1.18		$	0.80		$	0.56		$	3.18		$	2.42

Basic Earnings Per Average Common Share
Continuing operations	$	1.45		$	1.19		$	0.81		$	0.57		$	3.21		$	2.45
Discontinued operations		—			—			—			—			—			—

Net Income	$	1.45		$	1.19		$	0.81		$	0.57		$	3.21		$	2.45

Dividends Per Common Share	$	0.115		$	0.11		$	0.115		$	0.11		$	0.345		$	0.33

Diluted Average Common Shares Outstanding		72,124			74,094			72,275			73,191			72,173			73,671

Basic Average Common Shares Outstanding		71,482			73,268			71,623			72,228			71,566			72,839

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


*(in thousands)*	March 31, 2007		December 31, 2006		September 30, 2007		December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	68,616	$	10,307	$	2,711	$	10,307
Accounts receivable, net of allowance for doubtful accounts of $14,260 at March 31, 2007, and $13,961 at December 31, 2006		236,202		329,766
Accounts receivable, net of allowance for doubtful accounts of $12,648 at September 30, 2007, and $13,961 at December 31, 2006						168,250		329,766
Inventories, at average cost
Storage gas inventory		40,709		68,769		79,408		68,769
Materials and supplies		10,533		9,281		11,705		9,281
Liquified natural gas in storage		2,916		3,766		3,532		3,766
Regulatory asset		3,242		35,479		11,936		35,479
Deferred income taxes		14,943		—		19,496		—
Prepayments and other		31,706		32,211		27,892		32,211

Total current assets		408,867		489,579		324,930		489,579

Property, Plant and Equipment
Oil and gas properties, successful efforts method		2,213,798		2,163,065		2,408,996		2,163,065
Less accumulated depreciation, depletion and amortization		583,688		559,059		634,973		559,059

Oil and gas properties, net		1,630,110		1,604,006		1,774,023		1,604,006

Utility plant		1,074,473		1,060,562		1,097,790		1,060,562
Less accumulated depreciation		428,918		421,075		439,427		421,075

Utility plant, net		645,555		639,487		658,363		639,487

Other property, net		9,310		8,921		10,324		8,921

Total property, plant and equipment, net		2,284,975		2,252,414		2,442,710		2,252,414

Other Assets
Regulatory asset		38,185		38,385		30,568		38,385
Prepaid pension costs and postretirement assets		18,799		19,975		21,329		19,975
Deferred charges and other		38,378		36,534		43,991		36,534

Total other assets		95,362		94,894		95,888		94,894

TOTAL ASSETS	$	2,789,204	$	2,836,887	$	2,863,528	$	2,836,887

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


*(in thousands, except share and per share data)*	March 31, 2007			December 31, 2006			September 30, 2007			December 31, 2006
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year	$	100,000		$	100,000		$	10,000		$	100,000
Notes payable to banks		—			58,000			88,000			58,000
Accounts payable		138,682			194,448			152,074			194,448
Accrued taxes		94,120			42,960			50,735			42,960
Customers’ deposits		21,435			21,094			20,080			21,094
Amounts due customers		—			14,382			17,555			14,382
Accrued wages and benefits		14,745			24,548			19,315			24,548	��
Regulatory liability		28,397			33,871			12,876			33,871
Deferred income taxes		—			15,354			—			15,354
Other		68,373			65,985			68,080			65,985

Total current liabilities		465,752			570,642			438,715			570,642

Long-term debt		582,915			582,490			562,503			582,490

Deferred Credits and Other Liabilities
Asset retirement obligation		54,861			53,980			59,187			53,980
Pension liabilities		32,504			32,504			31,774			32,504
Regulatory liability		138,140			135,466			139,276			135,466
Deferred income taxes		240,522			241,146			240,415			241,146
Other		27,057			18,590			27,982			18,590

Total deferred credits and other liabilities		493,084			481,686			498,634			481,686

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, 74,063,549 shares issued at March 31, 2007, and 73,699,244 shares issued at December 31, 2006		741			737
Common stock, $0.01 par value; 150,000,000 shares authorized, 74,143,736 shares issued at September 30, 2007, and 73,699,244 shares issued at December 31, 2006								741			737
Premium on capital stock		418,616			412,989			426,696			412,989
Capital surplus		2,802			2,802			2,802			2,802
Retained earnings		939,337			844,880			1,048,688			844,880
Accumulated other comprehensive gain (loss), net of tax
Unrealized gain on hedges		463			50,555
Unrealized gain (loss) on hedges								(406	)		50,555
Pension and postretirement plans		(21,318	)		(23,177	)		(21,488	)		(23,177	)
Deferred compensation plan		15,835			13,956			16,032			13,956
Treasury stock, at cost (3,375,531 shares at March 31, 2007, and 3,253,337 shares at December 31, 2006)		(109,023	)		(100,673	)
Treasury stock, at cost (3,374,708 shares at September 30, 2007, and 3,253,337 shares at December 31, 2006)								(109,389	)		(100,673	)

Total shareholders’ equity		1,247,453			1,202,069			1,363,676			1,202,069

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	2,789,204		$	2,836,887		$	2,863,528		$	2,836,887

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


*Three months ended March 31,(in thousands)***	2007			2006
Nine months ended September 30, *(in thousands)*							2007			2006
Operating Activities
Net income	$	103,882		$	87,494		$	229,819		$	178,447
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		38,020			34,297			118,184			104,472
Deferred income taxes		1,125			15,961			(2,153	)		62,298
Change in derivative fair value		473			2,217			(1,079	)		(72	)
Gain on sale of assets		(302	)		(22	)		(368	)		(125	)
Other, net		8,958			2,239			13,194			3,216
Net change in:
Accounts receivable, net		46,502			44,740			104,218			129,062
Inventories		27,658			14,842			(12,829	)		(8,909	)
Accounts payable		(77,208	)		(39,424	)		(80,636	)		(36,839	)
Amounts due customers		4,525			(14,331	)		19,721			(30,767	)
Other current assets and liabilities		34,251			19,623			(3,339	)		(903	)

Net cash provided by operating activities		187,884			167,636			384,732			399,880

Investing Activities
Additions to property, plant and equipment		(66,604	)		(62,473	)		(253,821	)		(207,135	)
Acquisitions, net of cash acquired								(40,324	)		(4,334	)
Proceeds from sale of assets		861			37			1,058			184
Other, net		(684	)		(428	)		(2,184	)		(1,783	)

Net cash used in investing activities		(66,427	)		(62,864	)		(295,271	)		(213,068	)

Financing Activities
Payment of dividends on common stock		(8,244	)		(8,082	)		(24,830	)		(24,132	)
Issuance of common stock		338			2,970			1,503			356
Purchase of treasury stock		—			(2,522	)		—			(40,895	)
Payment of long-term debt		(44,615	)		(10	)
Payments of long-term debt								(155,109	)		(15,400	)
Proceeds from issuance of long-term debt		45,000			—			45,000			—
Debt issuance costs		(494	)		—			(494	)		—
Net change in short-term debt		(58,000	)		(98,000	)		30,000			(111,000	)
Tax benefit on stock compensation								5,870			1,220
Other		2,867			780			1,003			—

Net cash used in financing activities		(63,148	)		(104,864	)		(97,057	)		(189,851	)

Net change in cash and cash equivalents		58,309			(92	)		(7,596	)		(3,039	)
Cash and cash equivalents at beginning of period		10,307			8,714			10,307			8,714

Cash and Cash Equivalents at End of Period	$	68,616		$	8,622		$	2,711		$	5,675

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


	Three months ended March 31,						Three months ended September 30,						Nine months ended September 30,
*(in thousands)*	2007			2006			2007			2006			2007			2006
Operating Revenues	$	298,628		$	318,623		$	67,599		$	71,195		$	477,793		$	503,014

Operating Expenses
Cost of gas		168,138			194,050			31,088			32,311			252,584			284,192
Operations and maintenance		32,357			30,879			32,467			30,348			98,199			94,614
Depreciation and amortization		11,547			10,746
Depreciation								11,847			11,201			35,101			32,880
Income taxes
Current		24,388			24,163			(12,963	)		(10,525	)		12,335			15,308
Deferred		(315	)		(1,444	)
Deferred, net								6,596			5,677			6,003			2,186
Taxes, other than income taxes		18,149			19,221			5,870			6,256			32,175			33,811

Total operating expenses		254,264			277,615			74,905			75,268			436,397			462,991

Operating Income		44,364			41,008
Operating Income (Expense)								(7,306	)		(4,073	)		41,396			40,023

Other Income (Expense)
Allowance for funds used during construction		137			223			180			286			492			764
Other income		479			473			581			399			1,484			1,070
Other expense		(189	)		(229	)		(244	)		(207	)		(594	)		(701	)

Total other income		427			467			517			478			1,382			1,133

Interest Charges
Interest on long-term debt		2,964			3,237			2,963			3,220			8,956			9,702
Other interest expense		1,498			869			789			858			2,656			2,289

Total interest charges		4,462			4,106			3,752			4,078			11,612			11,991

Net Income	$	40,329		$	37,369
Net Income (Loss)							$	(10,541	)	$	(7,673	)	$	31,166		$	29,165

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


*(in thousands)*	March 31, 2007			December 31, 2006			September 30, 2007			December 31, 2006
ASSETS
Property, Plant and Equipment
Utility plant	$	1,074,473		$	1,060,562		$	1,097,790		$	1,060,562
Less accumulated depreciation		428,918			421,075			439,427			421,075

Utility plant, net		645,555			639,487			658,363			639,487

Other property, net		162			163			159			163

Current Assets
Cash and cash equivalents		6,960			8,765			1,658			8,765
Accounts receivable
Gas		130,322			159,101			62,845			159,101
Other		21,974			10,708			6,098			10,708
Affiliated companies		—			—
Allowance for doubtful accounts		(13,500	)		(13,200	)		(11,900	)		(13,200	)
Inventories, at average cost
Storage gas inventory		40,709			68,769			79,408			68,769
Materials and supplies		4,000			4,199			3,871			4,199
Liquified natural gas in storage		2,916			3,766			3,532			3,766
Deferred income taxes		14,023			13,251			13,590			13,251
Regulatory asset		3,242			35,479			11,936			35,479
Prepayments and other		2,558			3,557			3,276			3,557

Total current assets		213,204			294,395			174,314			294,395

Other Assets
Regulatory asset		38,185			38,385			30,568			38,385
Prepaid pension costs and postretirement assets		14,605			15,369			17,974			15,369
Deferred charges and other		7,608			6,326			7,155			6,326

Total other assets		60,398			60,080			55,697			60,080

TOTAL ASSETS	$	919,319		$	994,125		$	888,533		$	994,125

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


*(in thousands, except share data)*	March 31, 2007		December 31, 2006		September 30, 2007		December 31, 2006
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 March 31, 2007 and December 31, 2006		20		20
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at September 30, 2007 and December 31, 2006						20		20
Premium on capital stock		31,682		31,682		31,682		31,682
Capital surplus		2,802		2,802		2,802		2,802
Retained earnings		282,739		250,560		257,081		250,560

Total common shareholder’s equity		317,243		285,064		291,585		285,064
Long-term debt		209,141		208,756		208,647		208,756

Total capitalization		526,384		493,820		500,232		493,820

Current Liabilities
Notes payable to banks		—		58,000		54,000		58,000
Accounts payable		73,159		118,936		41,384		118,936
Affiliated companies		13,807		18,130		2,941		18,130
Accrued taxes		55,195		37,813		33,246		37,813
Customers’ deposits		21,435		21,094		20,080		21,094
Amounts due customers		—		14,382		17,555		14,382
Accrued wages and benefits		8,467		9,714		7,117		9,714
Regulatory liability		28,397		33,871		12,876		33,871
Other		9,017		8,225		9,364		8,225

Total current liabilities		209,477		320,165		198,563		320,165

Deferred Credits and Other Liabilities
Deferred income taxes		42,456		42,195		48,323		42,195
Regulatory liability		138,140		135,466		139,276		135,466
Other		2,862		2,479		2,139		2,479

Total deferred credits and other liabilities		183,458		180,140		189,738		180,140

Commitments and Contingencies

TOTAL LIABILITIES AND CAPITALIZATION	$	919,319	$	994,125	$	888,533	$	994,125

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


*Three months ended March 31,(in thousands)***	2007			2006
Nine months ended September 30, *(in thousands)*							2007			2006
Operating Activities
Net income	$	40,329		$	37,369		$	31,166		$	29,165
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		11,547			10,746			35,101			32,880
Deferred income taxes		(315	)		(1,444	)		6,003			2,186
Other, net		1,276			925			1,467			(2,259	)
Net change in:
Accounts receivable		14,348			23,002			77,469			109,070
Inventories		29,110			14,927			(10,077	)		(7,653	)
Accounts payable		(34,234	)		(29,569	)		(69,232	)		(43,315	)
Amounts due customers		4,525			(14,331	)		19,721			(30,767	)
Other current assets and liabilities		16,546			19,523			(8,479	)		69

Net cash provided by operating activities		83,132			61,148			83,139			89,376

Investing Activities
Additions to property, plant and equipment		(14,805	)		(18,603	)		(45,031	)		(58,111	)
Other, net		(553	)		(358	)		(1,781	)		(1,565	)

Net cash used in investing activities		(15,358	)		(18,961	)		(46,812	)		(59,676	)

Financing Activities
Dividends		(8,150	)		(7,624	)
Payment of long-term debt		(44,615	)		(10	)
Payment of dividends on common stock								(24,645	)		(22,875	)
Payments of long-term debt								(45,109	)		(5,400	)
Proceeds from issuance of long-term debt		45,000			—			45,000			—
Debt issuance costs		(494	)		—			(494	)		—
Net advances to affiliates		(4,323	)		(6,040	)
Net advances from (to) affiliates								(15,189	)		8,689
Net change in short-term debt		(58,000	)		(29,000	)		(4,000	)		(13,000	)
Other		1,003			—			1,003			—

Net cash used in financing activities		(69,579	)		(42,674	)		(43,434	)		(32 586	)

Net change in cash and cash equivalents		(1,805	)		(487	)		(7,107	)		(2 886	)
Cash and cash equivalents at beginning of period		8,765			7,169			8,765			7,169

Cash and Cash Equivalents at End of Period	$	6,960		$	6,682		$	1,658		$	4,283

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

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, 2006, 2005 and 2004 included in the 2006 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.

The quarterly information reflects the application of Statement of Financial Accounting Standard (SFAS) No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 requires that gains and losses from the sale of certain oil and gas properties and impairments on certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations in the current and prior periods. All other 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.

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 with modifications in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended Alagasco’s rate-setting methodology, RSE, without change, for a six-year period through January 1, 2008. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the Company and a hearing, the ~~Commission~~APSC votes to either modify or discontinue its operations. Alagasco is on 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. Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the ~~Commission,~~APSC, following a generic rate of return hearing, adjusts the equity returns of all major energy utilities operating under a similar methodology. 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. A corresponding reduction in rates is effective October 1, 2007 and December 1, 2007, under the provisions of RSE. Alagasco did not have a reduction in rates related to the return on average equity for the rate year ended 2006. A $14.3 million and a $15.8 million annual increase in revenues became effective December 1, 2006 and 2005, respectively. RSE limits the utility’s equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco’s operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls 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 is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. Alagasco’s O&M expense fell within the index range for the rate year ended September 30, 2007. The increase in O&M expense per customer was above the index range for the rate year ended September 30, 2006; as a result, the utility had a $1.5 million pre-tax decrease in revenues with ~~a corresponding~~the related rate reduction effective December 1, ~~2006, under the provisions of RSE.~~2006.

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

Energen Resources Corporation, Energen’s oil and gas subsidiary, periodically enters into derivative commodity instruments that qualify as cash flow hedges under 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 regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and 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. 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. ~~In cases where this arrangement exists, generally~~At September 30, 2007, the ~~credit ratings must be maintained at investment grade status to have any available~~ counterparty ~~credit. Adverse changes to the Company’s or Alagasco’s credit rating results in decreasing amounts of credit available~~agreements under ~~these contracts. The counterparties for these contracts do not extend credit to~~which the Company ~~or Alagasco in the event credit ratings are below investment grade. At March 31, 2007,~~had active positions did not include collateral posting requirements. Energen Resources was in a net gain position ~~in the aggregate~~ with four of its counterparties and ~~was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of March 31, 2007.~~a net loss with the remaining three. The Company believes the creditworthiness of these counterparties is satisfactory.

Energen Resources applies SFAS No. 133 as amended which requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of 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.

As of ~~March 31,~~September 30, 2007, ~~$10.8~~$6.6 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. Gains and losses on derivative instruments that are not accounted for as cash flow hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. For the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, Energen Resources recorded a ~~$0.7~~$0.1 million after-tax loss for the three months ended ~~March 31, 2007. Also, the~~September 30, 2007, and a $0.4 million after-tax gain year-to-date. The Company recorded ana $0.3 million after-tax gain ~~of approximately $91,000 during the first quarter of 2007~~year-to-date on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of ~~March 31,~~September 30, 2007, all of the Company’s hedges met the definition of a cash flow hedge. The Company had a net $0.3 million deferred tax asset and a net $31 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in OCI as of ~~March 31,~~September 30, 2007 and December 31, 2006, respectively. At ~~March 31,~~September 30, 2007, and December 31, 2006, the Company had ~~$22.3~~$20.8 million and $93.3 million, respectively, of current unrealized derivative gains recorded in accounts receivable. The Company had $5.5 million of non-current unrealized derivative gains recorded in deferred charges and other as of September 30, 2007. The Company also had ~~$2.1~~$11.7 million and $0.7 million of current unrealized derivative losses recorded in accounts payable at ~~March 31,~~September 30, 2007 and

December 31, 2006, respectively, and ~~$17.1~~$16.8 million and $11.9 million, respectively, of non-current unrealized derivative losses recorded in deferred credits and other liabilities. ~~The Company had $0.4 million of non-current unrealized derivative gains recorded in deferred charges and other as of March 31, 2007.~~

Energen Resources entered into the following transactions for the remainder of 2007 and subsequent years:

All hedge transactions are subject to the Company’s risk management policy, approved by the Board of Directors, which does not ~~permit~~authorize speculative positions. The Company formally documents all relationships between hedging instruments and hedged items at the inception of the hedge, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument’s effectiveness in hedging the exposure to the hedged transaction’s variability in cash flows attributable to the hedged risk will be assessed and measured. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2009.

On December 4, 2000, the APSC authorized Alagasco to engage in energy risk-management activities to manage the utility’s cost of 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. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco’s APSC-approved tariff. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” at ~~March 31,~~September 30, 2007, Alagasco recognized a ~~$15.3~~$3.2 million unrealized derivative ~~gain~~loss in accounts ~~receivable~~payable with a corresponding current regulatory ~~liability~~asset of ~~$15.3~~$3.2 million representing the fair value of derivatives. At December 31, 2006, Alagasco recognized an $11.5 million unrealized derivative loss in accounts payable with a corresponding current regulatory asset of $11.5 million representing the fair value of derivatives.


*(in thousands, except per share amounts)*	Three months ended March 31, 2007					Three months ended March 31, 2006					Three months ended September 30, 2007					Three months ended September 30, 2006
	Income		Shares	Per Share Amount		Income		Shares	Per Share Amount		Income		Shares	Per Share Amount		Income		Shares	Per Share Amount
Basic EPS	$	103,882	71,482	$	1.45	$	87,494	73,268	$	1.19	$	58,034	71,623	$	0.81	$	41,352	72,228	$	0.57
Effect of Dilutive Securities
Performance share awards			327					359					353					504
Stock options													211					337
Non-vested restricted stock													88					122

Diluted EPS											$	58,034	72,275	$	0.80	$	41,352	73,191	$	0.56


*(in thousands, except per share amounts)*											Nine months ended September 30, 2007					Nine months ended September 30, 2006
											Income		Shares	Per Share Amount		Income		Shares	Per Share Amount
Basic EPS											$	229,819	71,566	$	3.21	$	178,447	72,839	$	2.45
Effect of Dilutive Securities
Performance share awards													334					411
Stock options			237					360					192					316
Restricted stock			78					107
Non-vested restricted stock													81					105

Diluted EPS	$	103,882	72,124	$	1.44	$	87,494	74,094	$	1.18	$	229,819	72,173	$	3.18	$	178,447	73,671	$	2.42

For the three months and nine months ended ~~March 31,~~September 30, 2007, the Company had ~~232,285~~7,260 options and 239,545 options, respectively, that were excluded from the computation of diluted ~~EPS.~~EPS, as their effect were non-dilutive. The Company had no options that were excluded from the computation of diluted EPS ~~as of March 31,~~for the three months and the nine months ended September 30, 2006. For the three months and nine months ended ~~March 31,~~September 30, 2007 and the three months ended September 30, 2006, the Company had no shares of non-vested restricted stock that were excluded from the computation of diluted EPS. For the nine months ended September 30, 2006, the Company had 13,500 shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

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 March 31,						Three months ended September 30,						Nine months ended September 30,
*(in thousands)*	2007			2006			2007			2006			2007			2006
Operating revenues from continuing operations
Oil and gas operations	$	194,033		$	169,519		$	208,423		$	171,516		$	605,812		$	510,213
Natural gas distribution		298,628			318,623			67,599			71,195			477,793			503,014

Total	$	492,661		$	488,142		$	276,022		$	242,711		$	1,083,605		$	1,013,227

Operating income (loss) from continuing operations
Oil and gas operations	$	105,301		$	88,539		$	112,899		$	85,239		$	329,672		$	260,916
Natural gas distribution		68,437			63,727			(13,673	)		(8,921	)		59,734			57,517
Eliminations and corporate expenses		(540	)		(531	)		(594	)		(649	)		(1,671	)		(1,731	)

Total	$	173,198		$	151,735		$	98,632		$	75,669		$	387,735		$	316,702

Other income (expense)
Oil and gas operations	$	(7,504	)	$	(9,287	)	$	(7,567	)	$	(7,985	)	$	(23,406	)	$	(25,995	)
Natural gas distribution		(4,035	)		(3,639	)
Eliminations and other		(316	)		227

Total	$	(11,855	)	$	(12,699	)

Income from continuing operations before income taxes	$	161,343		$	139,036


*(in thousands)*	March 31, 2007			December 31, 2006
Identifiable assets
Oil and gas operations	$	1,775,947		$	1,822,216
Natural gas distribution		919,319			994,125

Subtotal		2,695,266			2,816,341
Eliminations and other		93,938			20,546

Total	$	2,789,204		$	2,836,887


Natural gas distribution		(3,235	)		(3,600	)		(10,230	)		(10,858	)
Eliminations and other		25			(441	)		(249	)		(255	)

Total	$	(10,777	)	$	(12,026	)	$	(33,885	)	$	(37,108	)

Income from continuing operations before income taxes	$	87,855		$	63,643		$	353,850		$	279,594


	Three months ended March 31,						Three months ended September 30,
*(in thousands)*	2007			2006		��	2007			2006
Net Income	$	103,882		$	87,494		$	58,034		$	41,352
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($20.2) million and $22.2 million		(32,982	)		36,244
Reclassification adjustment for derivative instruments, net of tax of ($10.5) million and $7 million		(17,110	)		11,443
Current period change in fair value of derivative instruments, net of tax of $6.8 million and $42.4 million								11,110			69,160
Reclassification adjustment for derivative instruments, net of tax of ($7.9) million and $1.7 million								(12,929	)		2,732
Pension and postretirement plans, net of tax of $0.4 million and $3.2 million								(810	)		5,972

Comprehensive Income							$	55,405		$	119,216


Pension and postretirement plans, net of tax of $1 million		1,859		—
					Nine months ended September 30,
*(in thousands)*					2007			2006
Net Income					$	229,819		$	178,447
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($5.9) million and $66.3 million						(9,640	)		108,097
Reclassification adjustment for derivative instruments, net of tax of ($25.3) million and $9.7 million						(41,321	)		15,855
Pension and postretirement plans, net of tax of $0.9 million and $3.2 million						1,689			5,972

Comprehensive Income	$	55,649	$	135,181	$	180,547		$	308,371


*(in thousands)*	March 31, 2007			December 31, 2006			September 30, 2007			December 31, 2006
Unrealized gain on hedges, net of tax of $0.3 million and $31 million	$	463		$	50,555
Pension and postretirement plans, net of tax of ($11.5) million and ($12.5) million		(21,318	)		(23,177	)
Unrealized gain on hedges, net of tax of ($0.3) million and $31 million							$	(406	)	$	50,555
Pension and postretirement plans, net of tax of ($11.6) million and ($12.5) million								(21,488	)		(23,177	)

Accumulated Other Comprehensive Income (Loss)	$	(20,855	)	$	27,378		$	(21,894	)	$	27,378

Stock Options: The 1997 Stock Incentive Plan provided for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 232,285 non-qualified option shares during the ~~three months ended March 31,~~first quarter of 2007 and 7,260 shares during the second quarter of 2007 with a weighted average grant-date fair value of ~~$17.33.~~$17.33 and $20.05, respectively.

Restricted Stock:In addition, the 1997 Stock Incentive Plan provided for the grant of restricted stock. In the ~~three~~nine months ended ~~March 31,~~September 30, 2007, 6,805 shares were awarded. These awards were valued based on the quoted market price of the Company’s common stock at the date of grant and have a three year vesting period.

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. During ~~the first quarter of~~ 2007 year-to-date, 85,906 awards with a weighted average grant-date fair value of ~~$18.70~~$22.34 were granted with stock appreciation rights. These awards have a three year vesting period.

The Energen Resources’ 2005 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 ~~first quarter of~~nine months ended September 30, 2007, Energen Resources awarded 5,242 Petrotech units with a weighted average grant-date fair value of ~~$49.65.~~$56.05. These awards have a three year vesting period.

The Company applies SFAS No. 144, which retains the previous asset impairment requirements of SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,” for loss recognition when the carrying value of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In addition, SFAS No. 144 requires that gains and losses on the sale of certain oil and gas properties and writedowns of certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for prior periods in accordance with SFAS No. 144. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale must be reported at the lower of the carrying amount or fair value. Energen Resources had no property sales under the provisions of SFAS No. 144 during the three months and nine months ended ~~March 31,~~September 30, 2007 and 2006.

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 March 31,						Three months ended September 30,						Nine months ended September 30,
*(in thousands)*	2007			2006			2007			2006			2007			2006
Components of net periodic benefit cost:
Service cost	$	1,703		$	1,620		$	1,703		$	1,613		$	5,109		$	4,839
Interest cost		2,794			2,666			2,771			2,679			8,336			8,037
Expected long-term return on assets		(3,267	)		(2,997	)		(3,267	)		(2,997	)		(9,802	)		(8,991	)
Actuarial loss		1,223			1,232			1,145			1,314			3,512			3,942
Prior service cost amortization		229			181			229			1			688			543
Transition amortization		—			1

Net periodic expense	$	2,682		$	2,703


Transition amortization		—		181		—		3
Settlement charge		3,532		326		5,657		326

Net periodic expense	$	6,113	$	3,117	$	13,500	$	8,699

In September 2007, the Company made a discretionary contribution of $6 million to the assets of a defined benefit qualified pension plan. The Company is not required to make pension contributions ~~in 2007~~ and does not currently plan on making additional discretionary contributions ~~to the qualified pension plans. For~~during 2007. The Company made benefit payments aggregating $0.5 million and $3.8 million for the three and nine months ended ~~March 31,~~September 30, 2007, ~~the Company made contributions aggregating $3.2 million~~respectively, to retirees of the nonqualified supplemental retirement ~~plans. The Company~~plans and expects to make additional ~~discretionary contributions~~benefit payments of approximately ~~$0.5~~$0.3 million ~~to nonqualified supplemental retirement plan assets~~ through the remainder of 2007. The Company recognized a settlement charge of ~~$2.1~~$0.3 million in the ~~first~~third quarter of 2007 ~~due to~~and $2.4 million in the year-to-date for the payment of lump sums from the nonqualified supplemental retirement ~~plans to certain key executives.~~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. This charge represented an acceleration of the unamortized actuarial losses as required under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits.”

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


	Three Months Ended March 31,						Three months ended September 30,						Nine months ended September 30,
*(in thousands)*	2007			2006			2007			2006			2007			2006
Components of net periodic benefit cost:
Service cost	$	256		$	313		$	256		$	304		$	767		$	912
Interest cost		923			939			923			920			2,769			2,761
Expected long-term return on assets		(1,250	)		(1,204	)		(1,250	)		(1,214	)		(3,751	)		(3,643	)
Actuarial gain		(315	)		(169	)		(315	)		(220	)		(945	)		(663	)
Transition amortization		479			480			479			479			1,438			1,438

Net periodic expense	$	93		$	359		$	93		$	269		$	278		$	805

For the three months and nine months ended ~~March 31,~~September 30, 2007, the Company made contributions aggregating ~~$0.3~~$0.2 million and $0.7 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately ~~$0.7~~$0.3 million to postretirement benefit plan assets through the remainder of 2007.

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 ~~$214~~$192 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 ~~152.5~~138.4 Bcf through April 2015.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities ~~existing~~ for gas delivered to customers subject to these guarantees are included in the ~~consolidated~~ balance ~~sheet.~~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 ~~March 31,~~September 30, 2007, the fixed price purchases under these guarantees had a maximum term outstanding through ~~March~~October 2008 and an aggregate purchase price of $4$11.5 million with a market value of ~~$4.4~~$10.8 million.

During 2007, Energen Resources entered into an agreement through March 2009 to secure a drilling rig necessary to execute a portion of its drilling plans. In the unlikely event that Energen Resources discontinues use of the drilling rig, Energen Resources’ total resulting exposure could be as much as approximately $11 million depending on the contractors ability to remarket the drilling rig.

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

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 2006, Energen Resources’ production associated with the lease was approximately 10 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.

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.

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

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

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

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

Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns), and five manufactured gas distribution sites (one of which it still owns). An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco’s share, if any, of such costs will not materially affect the financial position of Alagasco.

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


*(in thousands)*	March 31, 2007				December 31, 2006				September 30, 2007				December 31, 2006
*(in thousands)*	Current		Noncurrent		Current		Noncurrent
									Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Pension asset	$	—	$	28,074	$	—	$	28,476	$	—	$	19,999	$	—	$	28,476
Accretion and depreciation for asset retirement obligation		—		10,041		—		9,803		—		10,517		—		9,803
Gas supply adjustment		2,920		—		23,595		—		8,489		—		23,595		—
Risk management activities		—		—		11,543		—
Risk-management activities										3,224		—		11,543		—
Other		322		70		341		106		223		52		341		106

Total regulatory assets	$	3,242	$	38,185	$	35,479	$	38,385	$	11,936	$	30,568	$	35,479	$	38,385

Regulatory liabilities:
Enhanced stability reserve	$	3,951	$	—	$	3,951	$	—	$	3,951	$	—	$	3,951	$	—
Risk management activities		15,262		—		—		—
RSE adjustment		643		—		1,460		—		3,754		—		1,460		—
Unbilled service margin		8,508		—		27,233		—		5,138		—		27,233		—
Asset removal costs, net		—		116,825		—		114,520		—		121,826		—		114,520
Asset retirement obligation		—		13,022		—		12,833		—		13,401		—		12,833
Pension liability and postretirement benefits										—		3,031		—		7,220
Other										33		1,018		1,227		893

Total regulatory liabilities									$	12,876	$	139,276	$	33,871	$	135,466

Pension liability and postretirement benefits
   —      7,220    —      7,220
Other
   33    1,073    1,227    893

Total regulatory liabilities
   $ 28,397    $ 138,140    $ 33,871    $ 135,466

12.	~~12.~~ ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

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.

During year ended September 30, 2007, Energen Resources capitalized approximately $23 million of unproved leaseholds costs, largely shale related.

In December 2006, Energen Resources completed a purchase which expanded its operations in the San Juan Basin from Dominion Resources Inc. effective December 1, 2006 for approximately $30 million. Energen used its available cash and existing lines of credit to finance the acquisition.

In October 2006, Energen Resources sold a 50 percent interest in its lease position in various shale plays in Alabama to Chesapeake Energy Corporation (Chesapeake) for cash and a carried drilling interest. In addition, the two companies have signed an agreement to form an area of mutual interest (AMI) to focus on the further exploration and development of these shale plays throughout Alabama and a part of Georgia. Energen Resources received $75 million in cash from Chesapeake for a 50 percent interest in Energen Resources’ existing shale lease position of approximately 200,000 net acres in Alabama. Chesapeake also will pay for Energen Resources’ first $15 million of future drilling costs. Energen Resources had a gain of approximately $34.5 million after-tax in the fourth quarter of 2006 resulting from this sale of its lease position.

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.

In March 2007, Energen provided notice to the Bank of New York Trust Company of an April 19, 2007 voluntary redemption of $10 million Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026. Associated with this redemption, the Company will incur a call premium of 4.045%.

~~In April 2007, Energen provided notice to the Bank of New York Trust Company of a May 15, 2007 voluntary redemption of the $100 million Floating Rate Senior Notes due November 15, 2007.~~

14.	~~14.~~ RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)

The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” (FIN 48) as of January 1, 2007. This Interpretation prescribed a recognition threshold and measurement attribute for the financial statement recognition, measurement and disclosure of a tax position taken or expected to be taken in a tax return. As a result of the implementation of FIN 48, the Company recognized an approximate $1.2 million increase in the liability for unrecognized tax benefits and a decrease to the January 1, 2007 balance of retained earnings. As of the date of adoption and after the impact of recognizing the increase in liability noted above, the Company’s unrecognized tax benefits totaled $7.7 million, of which $3.9 million would favorably impact the Company’s effective tax rate, if recognized. The remaining $3.8 million of liability for unrecognized tax benefits represents a reclassification from previously established deferred tax liabilities pursuant to the adoption of FIN 48. The ~~Company’s tax returns for years 2003-2005 remain open to examination by the Internal Revenue Service and major state taxing jurisdictions. The~~ Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. As of January 1, 2007, the Company recognized approximately $484,000 in potential interest (net of tax benefit) and penalties associated with uncertain tax positions. The Company’s tax returns for years 2004-2006 remain open to examination by the Internal Revenue Service and major state taxing jurisdictions. The Company recognized approximately $1.8 million of previously unrecognized tax benefits in the current quarter as the result of the statute of limitations expiring for federal and state tax returns prior to 2004. This change recognized in the current quarter and the change in the unrecognized tax benefit expected within the next 12 months is not ~~expected to be~~considered material to the financial statements.

During September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which clarifies that fair value should be based on the assumptions market participants would use when pricing an asset or a liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS No. 157, fair value measurements would be separately disclosed by level within the fair value hierarchy effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact of this Statement.

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 is currently evaluating the impact of this Statement.

ITEM 2. ~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

There have been no material changes to the critical accounting policies and estimates from the information provided in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, included in the Form 10-K for the year ended December 31, 2006, except as follows:

As of January 1, 2007, the Company accounts for uncertain tax positions in accordance with the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes-an Interpretation of FASB Statement No. 109” (FIN 48). The application of income tax law is inherently ~~complex. Laws~~complex; laws and regulation in this area are voluminous and ~~are~~ often ambiguous. As such, the Company is required to make many subjective assumptions and judgments regarding income tax exposures. ~~Interpretation of~~Interpretations and guidance ~~surrounding~~related to income tax laws and regulation change over time. As such, it is possible that changes in the Company’s subjective assumptions and judgments ~~can~~could materially affect amounts recognized in the consolidated balance sheets and statements of income. Additional information related to the Company’s uncertain tax position is provided in Note 14 to the Unaudited Condensed Financial Statements.

Energen’s net income totaled ~~$103.9~~$58 million ($~~1.44~~0.80 per diluted share) for the three months ended ~~March 31,~~September 30, 2007 and compared favorably with net income of ~~$87.5~~$41.4 million ($~~1.18~~0.56 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 ~~March 31,~~September 30, 2007, of ~~$63.2~~$69.3 million as compared with ~~$49.7~~$49.9 million in the same quarter in the previous year. Energen Resources reported income from continuing operations of ~~$63.2~~$69.3 million in the current quarter as compared with $49.8 million in the same quarter last year. Significantly higher commodity prices (approximately ~~$13~~$18 million after-tax) and increased production volumes (approximately $2$6 million after-tax) were partially offset by increased lease operating expenses (approximately $1$2 million after-tax), and increased depreciation, depletion and amortization (DD&A) expense (approximately $3 million after-tax). In addition, the Section 199 Domestic Production Activities Deduction tax benefit on qualified oil and gas production income increased in the current quarter (approximately $2 million after-tax) as compared to the same period in the prior year. Energen’s natural gas utility, Alagasco, reported a net loss of $10.5 million in the third quarter of 2007 compared to a net loss of $7.7 million in the same period last year. Alagasco had a reduction in net income in period comparisons related to various components of the utility’s rate methodology at the end of the year for rate-setting purposes (approximately $2 million after-tax). In addition, net income was affected by the timing of the recovery of earnings on a higher level of equity in quarter comparisons. The utility historically records a net loss in the third quarter when the heating load is at its lowest level of the year.

For the 2007 year-to-date, Energen’s net income totaled $229.8 million ($3.18 per diluted share) and compared favorably to net income of $178.4 million ($2.42 per diluted share) for the same period in the prior year. Energen Resources had net income for the nine months ended September 30, 2007, of $199.4 million as compared with $150.1 million in the previous period. Energen Resources generated income from continuing operations of $199.4 million in the current year-to-date as compared with $150 million in the same period last year primarily as a result of higher commodity prices (approximately $52 million after-tax), increased production volumes (approximately $8 million after-tax) and the Section 199 deduction (approximately $5 million after-tax) partially offset by the impact of increased lease operating expenses (approximately $8 million after-tax), higher DD&A expense (approximately $7 million after-tax) and increased administrative expenses (approximately $3 million after-tax). ~~Energen’s natural gas utility, Alagasco, reported~~Alagasco’s net income of ~~$40.3~~$31.2 million increased in the ~~first quarter of 2007~~current year-to-date compared to a net income of ~~$37.4~~$29.2 million in the same period ~~last year largely reflecting~~in the previous year. The utility’s ability to earn on a higher level of ~~equity.~~equity as well as the end of the year rate-setting mechanisms affected net income in period comparisons. In addition, net income in the prior year was negatively affected by customer conservation related to high gas costs during the winter heating season.

Revenues from oil and gas operations rose ~~14.5~~21.5 percent to ~~$194~~$208.4 million for the three months ended ~~March 31,~~ September 30,

2007 and 18.7 percent to $605.8 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 ~~4.8~~10.1 percent to ~~$7.93~~$7.49 per thousand cubic feet (Mcf), while oil revenue per unit of production increased 2726.5 percent to ~~$58.36~~$65.06 per barrel. Natural gas liquids revenue per unit of production increased ~~37.9~~23.6 percent to an average price of ~~$0.80~~$0.89 per gallon. In the year-to-date, revenue per unit of production for natural gas increased 10.5 percent to $7.78 per thousand cubic feet (Mcf), oil revenue per unit of production increased 25.8 percent to $62.58 per barrel and natural gas liquids revenue per unit of production rose 26.9 percent to an average price of $0.85 per gallon.

Production increased primarily due to additional development activities in the San Juan ~~Basin~~and Permian basins partially offset by normal production declines. Natural gas production from continuing operations in the ~~first~~third quarter rose ~~1.4~~3.1 percent to ~~15.5~~16.5 billion cubic feet (Bcf) ~~and~~, while oil volumes increased ~~1.1~~13.3 percent to ~~927~~1,025 thousand barrels (MBbl). Natural gas liquids production ~~increased 13.9~~decreased 3.9 percent to ~~18.9~~19.6 million gallons (MMgal) ~~primarily related~~. For the year-to-date, natural gas production from continuing operations increased 1.4 percent to ~~development activity in the San Juan Basin.~~47.7 Bcf, oil volumes rose 5.9 percent to 2,898 MBbl and natural gas liquids production increased 1 percent to 57.6 MMgal. Natural gas comprised approximately 65 percent of Energen Resources’ production for the current ~~quarter.~~quarter and the year-to-date.

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. The Company recorded an after-tax gain of approximately ~~$91,000 during the first quarter of 2007~~$0.3 million year-to-date on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. For the three months and nine months ended ~~March 31,~~September 30, 2007, the Company recorded a ~~$0.7~~$0.1 million after-tax loss and a $0.4 million after-tax gain, respectively, for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges.

Operations and maintenance (O&M) expense increased ~~$6.1~~$3.9 million for the ~~quarter.~~quarter and $15.7 million in the year-to-date. Lease operating expense (excluding production taxes) increased by ~~$1.5~~$3.4 million for the quarter largely due to higher field services costs and increased repairs and maintenance expense in the Permian and the San Juan basins. In the year-to-date, lease operating expense (excluding production taxes) rose $12.4 million primarily due to a general rise in field services costs, additional compression costs, increased repair and maintenance expense in the Permian Basin and higher transportation costs related to increased San Juan Basin production, increased ad valorem taxes and higher maintenance expense in the Permian Basin; partially offsetting these increases was lower workover expense in the current period primarily in the San Juan Basin.production. Administrative expense increased ~~$4.5~~$1 million and $5.1 million for the three and nine months ended ~~March 31,~~September 30, 2007, respectively, largely due to increased labor-related ~~costs.~~expenses. Exploration expense ~~remained stable~~declined $0.6 million in the ~~first~~third quarter of ~~2007.~~2007 and $1.8 million in the year-to-date primarily due to decreased exploratory efforts.

Energen Resources’ DD&A expense for the quarter rose ~~$2.9 million.~~$5.1 million and increased $11.5 million year-to-date. The average depletion rate for the current quarter was ~~$1.09~~$1.14 per Mcfe as compared to ~~$0.99~~$0.98 per Mcfe in the same period a year ago. For the nine months ended September 30, 2007, the average depletion rate was $1.11 as compared to $0.98 in the previous period. The increase in the current quarter and year-to-date per unit depletion expense was largely due to higher rates resulting from a decline in year-end reserve prices ~~and~~combined with higher development costs. Increased production volumes also contributed to the increase in DD&A expense in the quarter and year-to-date comparisons.

Energen Resources’ expense for taxes other than income taxes was ~~$1.3~~$0.1 million ~~lower~~higher in the ~~first~~third quarter ~~and primarily reflected~~largely due to production-related taxes that were higher as a result of increased oil and natural gas liquid commodity market prices partially offset by decreased natural gas commodity market prices. For the nine months ended

September 30, 2007, the $0.6 million decrease in taxes other than income taxes primarily reflected lower production-related taxes due to decreased natural gas and oil commodity market prices; these decreases were partially offset by higher production volumes and increased natural gas liquids commodity market prices. Commodity market prices exclude the effects of derivative instruments.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the impairments on certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets.” Energen Resources had no property sales under the provisions of SFAS No. 144 during the three months and nine months ended ~~March 31,~~September 30, 2007 and 2006.

Natural gas distribution revenues decreased ~~$20~~$3.6 million for the quarter largely due to a $2.1 million reduction to revenue in period comparisons related to the utility’s rate setting mechanisms at the end of the rate year. 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. Alagasco’s O&M expense per customer exceeded its inflation-based cost control measure at the end of the 2006 rate year; as a result the utility had a $1.5 million decrease in ~~commodity gas costs and~~revenues in the three months ending September 30, 2006. Revenues were also affected in quarter period comparisons by the timing of the utility’s earning on a ~~slight decrease in customer usage.~~higher level of equity. For the third quarter, weather was comparable with the same period last year. Residential sales volumes ~~declined 0.9~~decreased 4 percent, ~~and~~ commercial and industrial customer sales volumes decreased ~~1.4 percent.~~0.9 percent while transportation volumes declined 1.7 percent in period comparisons. Revenues for the year-to-date declined $25.2 million largely due to a decrease in gas costs and the adjustments for rate-setting purposes as described above. For the nine months ended September 30, 2007, weather that was 1.2 percent warmer than in the previous period contributed to a 1.7 percent decline in residential sales volumes and a 2.2 percent decrease in commercial and industrial customer sales volumes. Transportation volumes increased ~~0.5~~1.2 percent in period comparisons. A decline in gas costs ~~partially offset by a slight increase in gas purchase volumes~~primarily resulted in a ~~13.4~~3.8 percent decrease in cost of gas for the ~~quarter.~~quarter and an 11.1 percent decrease year-to-date. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the GSA rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment to certain customers’ bills designed to substantially remove the effect of departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

As discussed more fully in Note 2 to the Unaudited Condensed Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend Alagasco’s rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to Alagasco and a hearing, the ~~Commission~~APSC votes to either modify or discontinue its operation.

O&M expense increased ~~4.8~~7 percent in the current quarter primarily due to increased labor-related costs, including a settlement charge for a defined benefit pension plan. In the nine months ended September 30, 2007, O&M expense rose 3.8 percent primarily due to higher labor-related costs, including settlement charges for the nonqualified supplemental retirement plans and ~~higher insurance costs~~the defined benefit pension plans, partially offset by decreased bad debt expense. A ~~7.5~~5.8 percent increase in depreciation

expense in the current quarter and a 6.8 percent increase in the year-to-date was primarily due to normal 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.

Interest expense for the Company decreased $1$0.8 million in the ~~first~~third quarter of 2007 ~~primary~~largely due to the May 2007 voluntary call of the $100 million Floating Rate Senior Notes due November 15, 2007, partially offset by higher borrowings at Energen Resources. For the year-to-date, interest expense declined $2.2 million primarily due to lower borrowings at Energen ~~Resources.~~Resources along with decreased interest expense related to the redemption of the $100

million Floating Rate Senior Notes. Income tax expense for the Company increased ~~$5.9~~$7.5 million in the current quarter and $22.9 million year-to-date largely due to higher pre-tax ~~income.~~income partially offset by the after-tax impact of the Section 199 deduction.

Cash flows from operations for the year-to-date were ~~$188.8~~$384.7 million as compared to ~~$167.6~~$399.9 million in the prior period. Operating cash flow benefited from higher realized commodity prices and production volumes at Energen ~~Resources.~~Resources partially offset by an increase in income taxes payable related to depreciation and basis differences in the current period and the prior period utilization of minimum tax credit. The Company’s working capital needs were also highly influenced by the timing of payments. Working capital needs at Alagasco were primarily affected by decreased gas costs compared to the prior period and ~~decreased storage~~the timing of recovery of gas ~~inventory.~~costs from customers compared to the prior period.

The Company had a net outflow of cash from investing activities of ~~$66.4~~$295.3 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2007 primarily due to additions of property, plant and equipment. Energen Resources invested ~~$53.4~~$254.8 million in capital expenditures primarily related to the development of oil and gas ~~properties.~~properties including an $18 million acquisition in the Permian Basin and approximately $22 million of unproved leaseholds, primarily shale related. Utility capital expenditures totaled ~~$14.8~~$45 million in the year-to-date and primarily represented expansion and replacement of its distribution system and support facilities.

The Company used ~~$64.2~~$97.1 million for net financing activities in the year-to-date primarily ~~due to~~for the ~~repayment~~payment of ~~short-term borrowings and~~ dividends ~~paid~~ to common ~~shareholders. The~~shareholders and the early redemption of $100 million Floating Rate Senior Notes due November 15, 2007, $34.4 million of 6.75% Notes maturing September 1, 2031, $10 million of Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026. Partially offsetting these uses of cash was the January 2007 issuance by Alagasco of $45 million in long-term debt with an interest rate of 5.9% due January 15, ~~2037 was largely offset by the redemption of $34.4 million of 6.75% Notes maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026.~~2037.

Energen plans to continue investing significant capital in Energen Resources’s oil and gas production operations. In the three-year period ending December 31, 2009, the Company expects to invest approximately ~~$660~~$860 million primarily in its four major areas of operation. For 2007, the Company expects its oil and gas capital spending to total approximately ~~$275~~$330 million, including ~~$260~~$275 million for the development of existing ~~properties.~~properties, $18 million for an acquisition in the Permian Basin in May 2007 and approximately $23 million in capitalized unproved leasehold costs. Capital investment at Energen Resources in 2008 is expected to approximate ~~$190~~$300 million, including ~~$185~~approximately $285 million for the development of existing properties.

The Company also may allocate additional capital during this three-year period for other oil and gas activities such as property acquisitions, additional accelerated development of existing properties and the exploration and 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 sold to Chesapeake Energy Corporation (Chesapeake) a 50 percent interest in its unproved lease position of approximately 200,000 acres in various shale plays in Alabama for $75 million and a $15 million carried drilling interest. In addition, the two companies signed an agreement to form an area of mutual interest (AMI) through which they will pursue new leases, exploration, development and operations on a 50-50 basis, for at least the next 10 years. Energen Resources and Chesapeake continue to lease shared acreage in the AMI, which encompasses Alabama and some of Georgia in advance of drilling. As of October 12, 2007, Energen Resources’ net acreage position ~~as of April 15, 2007,~~ totaled approximately ~~180,000~~250,000 acres and represents multiple shale opportunities. The Company has not included in its capital spending estimates discussed above any amounts associated with ~~future potential development and/or~~ exploratory drilling in the ~~AMI.~~AMI and/or future potential development.

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. Energen has $100 million Floating Rate Senior Notes due November 2007 that it plans to voluntarily redeem in May 2007. In March 2007, Energen provided notice to the Bank of New York Trust Company of an April 19, 2007 voluntary redemption of $10 million Medium-Term Notes, Series A, with an annual interest rate of 8.09% due September 15, 2026. Energen currently has available short-term credit facilities aggregating $415 million to help finance its growth plans and operating needs.

Energen also plans to consider stock repurchases as a capital ~~investment option over the next 24-36 months.~~investment. In May 2006, Energen began a buy-back of its common stock under an existing stock repurchase plan. In June 2006, the Company’s Board of Directors authorized an additional 9 million shares of common stock for repurchase. Energen may buy shares from time to time on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. During 2006, the Company purchased 2.2 million shares at an average price of $39.08 per share. The Company did not repurchase shares of common stock for this program during the ~~first quarter of~~nine months ended September 30, 2007. The Company currently plans to continue utilizing internally generated cash flow to fund any future stock repurchases.

Energen Resources has experienced various market driven conditions generally caused by the increased commodity price environment including, but not limited to, higher workover and maintenance expenses, increased taxes 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.

Energen Resources hedges its exposure to estimated commodity 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 regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and 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. 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. ~~In cases where this arrangement exists, generally~~At September 30, 2007, the ~~credit ratings must be maintained at investment grade status to have any available~~ counterparty ~~credit. Adverse changes to the Company’s credit rating will result in decreasing amounts of credit available~~agreements under ~~these contracts. The counterparties for these contracts do not extend credit to~~which the Company ~~in the event credit ratings are below investment grade. At March 31, 2007,~~had active positions did not include collateral posting requirements. Energen Resources was in a net gain position ~~in the aggregate~~ with four of its counterparties and ~~was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of March 31, 2007.~~a net loss with the remaining three. The Company believes the creditworthiness of these counterparties is satisfactory. These hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not ~~permit~~authorize speculative positions.

Energen Resources entered into the following transactions for the remainder of 2007 and subsequent years:


2008	2,398 MBbl	~~240~~	Basis Swaps
2008	1,620 MBbl	**	Basis Swaps
Natural Gas Liquids
2007	~~33.6~~ 11.2 MMGal	$0.93 Gal	Liquids Swaps
2008	41.3 MMGal	$0.93 Gal	Liquids Swaps
~~4.5 MMGal~~2008	*6.4 MMGal	$1.15 Gal	Liquids Swaps
~~$0.87 Gal~~2009	*10.1 MMGal	$1.05 Gal	Liquids Swaps

Realized prices are anticipated to be lower than NYMEX prices due to basis differences and other factors.

The Company’s efforts to minimize commodity price volatility through hedging is reflected in Alagasco’s current rates. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (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. Sustained ~~high~~higher natural gas prices may decrease Alagasco’s customer base and could result in a further decline of per customer use and number of customers. The utility will continue to monitor its bad debt reserve and will make adjustments as required based on the evaluation of its receivables which are impacted by natural gas prices.

Alagasco maintains an investment in storage gas that is expected to average approximately $62 million in 2007 but will vary depending upon the price of natural gas. During 2007 and 2008, Alagasco plans to invest an estimated ~~$59~~$61 million and $62 million, respectively, in utility capital expenditures for normal distribution and support systems. Over the three-year period ending December 31, 2009, Alagasco anticipates capital investments of approximately ~~$185~~$189 million. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. Alagasco issued $45 million in long-term debt with an interest rate of 5.9% in January 2007 and ~~recalled~~redeemed $34.4 million of 6.75% Notes maturing September 1, 2031 and $10 million of 7.97% Medium-Term Notes maturing September 23, 2026 in the same period in order to capitalize on lower interest rates.

Access to capital is an integral part of the Company’s business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. Moody’s Investors Services (Moody’s) recently reevaluated the business and financial profiles of the Company. On September 25, 2007, Moody’s downgraded the debt rating of Energen to Baa3 senior unsecured from Baa2. Energen’s debt rating of Baa3 remains investment grade and reflects Moody’s assignment of increased exposure to the Company related to the growth of its oil and gas operations. Moody’s also confirmed the debt rating of Alagasco during this review as A1 senior unsecured. On October 31, 2007, Standard & Poor’s affirmed its BBB+ corporate credit rating on Energen and Alagasco; the outlook remained stable. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets, continued access could be adversely affected by future economic and business conditions and credit rating downgrades. To help finance its growth plans and operating needs, the Company currently has available short-term credit facilities aggregating $415 million of which Energen has available $255 million, Alagasco has available $110 million and $50 million is available to either Company.

Energen expects to pay annual cash dividends of $0.46 per share on the Company’s common stock in 2007. 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.

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, 2006.

The Company adopted the provisions of FIN 48 as of January 1, 2007. This Interpretation prescribed a recognition threshold and measurement attribute for the financial statement recognition, measurement and disclosure of a tax position taken or expected to be taken in a tax return. As a result of the implementation of FIN 48, the Company recognized an approximate $1.2 million increase in the liability for unrecognized tax benefits and a decrease to the January 1, 2007 balance of retained earnings. As of the date of adoption and after the impact of recognizing the increase in liability noted above, the Company’s unrecognized tax benefits totaled $7.7 million, of which $3.9 million would favorably impact the Company’s effective tax rate, if recognized. The remaining $3.8 million of liability for unrecognized tax benefits represents a reclassification from previously established deferred tax

liabilities pursuant to the adoption of FIN 48. ~~The Company’s tax returns for years 2003-2005 remain open to examination by the Internal Revenue Service and major state taxing jurisdictions.~~ The Company recognizes potential accrued interest and penalties related to unrecognized tax benefits in income tax expense. As of January 1, 2007, the Company recognized approximately $484,000 in potential interest (net of tax benefit) and penalties associated with uncertain tax positions. The Company’s tax returns for years 2004-2006 remain open to examination by the Internal Revenue Service and major state taxing jurisdictions. The Company recognized approximately $1.8 million of previously unrecognized tax benefits in the current quarter as the result of the statute of limitations expiring for federal and state tax returns prior to 2004. This change recognized in the current quarter and the change in the unrecognized tax benefit expected within the next 12 months is not ~~expected to be~~considered material to the financial 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, 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 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:There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned development, acquisition, and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors.

Energen Resources’ Hedging:Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future commodity prices could materially affect the Company’s financial position, results of operations and cash flows; furthermore, such risk mitigation activities may cause the

Company’s financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such ~~risk-mitigation~~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 gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. 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.


	Three months ended March 31,				Three months ended September 30,					Nine months ended September 30,
*(in thousands, except sales price data)*	2007		2006		2007			2006		2007		2006
Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$	123,225	$	116,084	$	123,499		$	108,795	$	371,436	$	331,073
Oil		54,084		42,142		66,689			46,529		181,388		136,146
Natural gas liquids		15,042		9,677		17,486			14,668		49,076		38,152
Other		1,682		1,616		749			1,524		3,912		4,842

Total	$	194,033	$	169,519	$	208,423		$	171,516	$	605,812	$	510,213

Production volumes from continuing operations
Natural gas (MMcf)		15,547		15,327		16,495			16,004		47,732		47,056
Oil (MBbl)		927		917		1,025			905		2,898		2,736
Natural gas liquids (MMgal)		18.9		16.6		19.6			20.4		57.6		57.1
Production volumes from continuing operations (MMcfe)		23,806		23,209		25,445			24,340		73,350		71,625
Total production volumes (MMcfe)		23,805		23,209		25,445			24,340		73,349		71,624
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)	$	7.93	$	7.57	$	7.49		$	6.80	$	7.78	$	7.04
Oil (barrel)	$	58.36	$	45.94	$	65.06		$	51.43	$	62.58	$	49.75
Natural gas liquids (gallon)	$	0.80	$	0.58	$	0.89		$	0.72	$	0.85	$	0.67
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)	$	7.92	$	7.57	$	7.49		$	6.80	$	7.78	$	7.04
Oil (barrel)	$	58.36	$	45.94	$	65.06		$	51.43	$	62.45	$	49.75
Natural gas liquids (gallon)	$	0.80	$	0.58	$	0.89		$	0.72	$	0.85	$	0.67
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)	$	6.56	$	8.00	$	5.82		$	6.10	$	6.45	$	6.70
Oil (barrel)	$	52.79	$	56.54	$	69.70		$	64.94	$	60.91	$	61.91
Natural gas liquids (gallon)	$	0.75	$	0.71	$	0.99		$	0.88	$	0.89	$	0.81
Other data from continuing operations
Lease operating expense (LOE)
LOE and other	$	35,409	$	33,862	$	38,706		$	35,305	$	113,236	$	100,789
Production taxes		12,011		13,093	$	12,968		$	12,602	$	38,568	$	38,454

Total	$	47,420	$	46,955	$	51,674		$	47,907	$	151,804	$	139,243

Depreciation, depletion and amortization	$	26,473	$	23,551	$	29,610		$	24,475	$	83,083	$	71,592
Capital expenditures	$	53,395	$	44,905	$	94,274		$	61,049	$	254,795	$	156,606
Exploration expenditures	$	97	$	109	$	1,396		$	1,986	$	1,671	$	3,512
Operating income	$	105,301	$	88,539	$	112,899		$	85,239	$	329,672	$	260,916
Natural Gas Distribution
Operating revenues
Residential	$	203,798	$	218,506	$	35,685		$	36,635	$	306,312	$	322,635
Commercial and industrial		77,722		84,557		21,384			22,300		130,279		139,713
Transportation		14,567		12,735		10,575			10,115		36,509		33,111
Other		2,541		2,825		(45	)		2,145		4,693		7,555

Total	$	298,628	$	318,623	$	67,599		$	71,195	$	477,793	$	503,014

Gas delivery volumes (MMcf)
Residential		11,579		11,685		1,537			1,601		16,303		16,581
Commercial and industrial		4,872		4,941		1,520			1,534		8,373		8,559


Transportation		13,420		13,359		12,779			12,999			38,396		37,947

Total		29,871		29,985		15,836			16,134			63,072		63,087

Other data
Depreciation and amortization	$	11,547	$	10,746	$	11,847		$	11,201		$	35,101	$	32,880
Capital expenditures	$	14,967	$	18,845	$	14,023		$	18,512		$	45,596	$	58,947
Operating income	$	68,437	$	63,727	$	(13,673	)	$	(8,921	)	$	59,734	$	57,517

ITEM 3. ~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

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 regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. These counterparties have been deemed creditworthy by the Company and have agreed in certain instances to post collateral with the Company when unrealized gains on hedges exceed certain specified contractual amounts. Notwithstanding these agreements, the Company is at risk for economic loss based upon the creditworthiness of its counterparties. In some contracts, the amount of credit allowed before Energen Resources and Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. All hedge transactions are subject to the Company’s risk management policy and approved by the Board of Directors, which does not ~~permit~~authorize 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, 2009.

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 ~~March 31,~~September 30, 2007, was minimal ~~since approximately 85 percent of~~as all long-term debt obligations were at fixed rates.

~~At the annual meeting of shareholders held on April 25, 2007, Energen shareholders took the following actions:~~


	~~Votes cast against amendment~~	~~2,099,819~~
	~~Abstentions~~	~~413,666~~

d.	~~Ratified of the appointment of PricewaterhouseCoopers LLP as the Company’s independent registered public accounting firm for 2007:~~

	~~Votes cast for amendment~~	~~62,509,710~~
	~~Votes cast against amendment~~	~~208,010~~
	~~Abstentions~~	~~113,741~~

ITEM 6. ~~EXHIBITS~~

EXHIBITS

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.


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


Energen Corporation	Large accelerated filerx	Accelerated filer¨	Non-accelerated filer¨
Alabama Gas Corporation	Large accelerated filer¨	Accelerated filer¨	Non-accelerated filerx


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


		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	21

	Selected Business Segment Data of Energen Corporation	2829

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	3031

Item 4.	Controls and Procedures	3132

	PART II:OTHER INFORMATION

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32

~~Item 4.~~	~~Submission of Matters to a Vote of Security Holders~~	3233

Item 6.	Exhibits	33

SIGNATURES		34


Production Period	Total Hedged Volumes		Average Contract Price		Description
Natural Gas
~~2007~~		~~9.7 Bcf~~		~~$9.28 Mcf~~
2007	3.1 Bcf		$9.27 Mcf		NYMEX Swaps
	7.4 Bcf		$7.83 Mcf		Basin Specific Swaps
2008	29.2 Bcf		$8.55 Mcf		NYMEX Swaps
	14.5 Bcf		$7.66 Mcf		Basin Specific Swaps
2009	14.4 Bcf		$7.92 Mcf		Basin Specific Swaps
~~22.1 Bcf~~Gas Basis Differential	~~$7.83 Mcf~~		~~Basin Specific Swaps~~
~~2008~~	~~3.6 Bcf~~
2008	~~$8.47 Mcf~~ 10.8 Bcf		~~NYMEX~~*		Basis Swaps
Oil
~~2007~~		~~2,035 MBbl~~		~~$70.00 Bbl~~
2007	~~NYMEX Swaps~~
~~2008~~ 671 MBbl	~~1,920 MBbl~~ $69.94 Bbl		~~$66.89 Bbl~~ NYMEX Swaps
2008	~~NYMEX Swaps~~
~~2009~~ 2,973 MBbl	~~900 MBbl~~ $68.82 Bbl		~~$56.25 Bbl~~ NYMEX Swaps
2009	1,620 MBbl		$64.23 Bbl		NYMEX Swaps
Oil Basis Differential
~~2007~~		~~1,774 MBbl~~		*
2007	~~Basis Swaps~~
~~2008~~ 584 MBbl	~~1,020 MBbl~~ *		* Basis Swaps
2008	2,398 MBbl		*		Basis Swaps
2009	1,620 MBbl		*		Basis Swaps
Natural Gas Liquids
~~2007~~		~~33.6 MMGal~~		~~$0.93 Gal~~
2007	~~Liquids Swaps~~
~~2008~~ 11.2 MMGal	~~4.5 MMGal~~ $0.93 Gal		~~$0.87 Gal~~ Liquids Swaps
2008	41.3 MMGal		$0.93 Gal		Liquids Swaps


Energen Corporation	$0.01 par value	~~71,732,070~~71,787,138 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares


(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.


Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs**
January 1, 2007 through January 31, 2007	108,046	*	$	46.27	—	8,992,700
February 1, 2007 through February 28, 2007	—			—	—	8,992,700
March 1, 2007 through March 31, 2007	30,523	*	$	48.18	—	8,992,700

Total	138,569		$	46.69	—	8,992,700


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, 2007 through July 31, 2007	—			—	—	8,992,700
August 1, 2007 through August 31, 2007	1,580	*	$	55.74	—	8,992,700
September 1, 2007 through September 30, 2007	246	*	$	54.67	—	8,992,700

Total	1,826		$	55.60	—	8,992,700


a.	Elected the following Directors to serve for three-year terms expiring in 2010:

	Director	Votes cast for	Votes withheld
	Stephen D. Ban	60,118,303	2,713,158
	Julian W. Banton	60,646,650	2,184,811
	T. Michael Goodrich	60,659,285	2,172,176
	Wm. Michael Warren, Jr.	59,068,210	3,763,251

	Elected the following Director to serve for a one-year term expiring in 2008:

	Director	Votes cast for	Votes withheld
	James T. McManus II	59,944,857	2,886,604

b.	Approved amendments to change in control and related provisions of the 1997 Stock Incentive Plan and continued the Plan’s qualification for purposes of Section 162(m) of the Internal Revenue Code of 1986, as amended:

	Votes cast for amendment	58,630,575
	Votes cast against amendment	3,724,136
	Abstentions	476,750

c.	Re-approved the Annual Incentive Compensation Plan to continue the Plan’s qualification for purposes of Section 162(m) of the Internal Revenue Code of 1986, as amended:

	Votes cast for amendment	60,317,976


10	3	- ~~Energen~~Alabama Gas Corporation ~~1997 Stock Incentive Plan (As~~By-Laws as Amended ~~Effective January 1, 2007)~~through October 24, 2007

31	~~(a)~~ 31(a)	- Section 302 Certificate required by Rule 13a-14(a) or Rule 15d-14(a)

31	~~(b)~~ 31(b)	- Section 302 Certificate required by Rule 13a-14(a) or Rule 15d-14(a)

32		- Section 906 Certificate pursuant to 18 U.S.C. Section 1350


		ENERGEN CORPORATION ALABAMA GAS CORPORATION

~~May 8,~~November 6, 2007		By	/s/ ~~Wm. Michael Warren, Jr.~~James T. McManus, II
	~~Wm. Michael Warren, Jr.~~
	~~Chairman~~James T. McManus, II Chief Executive Officer and President of Energen Corporation and Chief Executive Officer of Alabama Gas Corporation



	November 6, 2007	~~of Energen Corporation, Chairman and~~ ~~Chief Executive Officer of Alabama~~
		~~Gas Corporation~~

~~May 8, 2007~~	By	/s/ Charles W. Porter, Jr.
		~~Charles W. Porter, Jr.~~
		Charles W. Porter, Jr. Vice President, Chief Financial Officer
		and Treasurer of Energen Corporation
		and Alabama Gas Corporation



~~May 8,~~November 6, 2007		By	/s/ Grace B. Carr
	~~Grace B. Carr~~
	Grace B. Carr Vice President and Controller of Energen Corporation



	November 6, 2007	~~Corporation~~

~~May 8, 2007~~	By	/s/ Paula H. Rushing
		~~Paula H. Rushing~~
		Paula H. Rushing Vice President-Finance of Alabama Gas
		Corporation