Energen (EGN) 10-Q 2005 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

FORM 10-Q

|X|	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005

OR

|  |	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM ___ TO ___

Commission			IRS Employer
File		State of	Identification
Number	Registrant	Incorporation	Number
1-7810	Energen Corporation	Alabama	63-0757759
2-38960	Alabama Gas Corporation	Alabama	63-0022000

605 Richard Arrington Jr. Boulevard North
Birmingham, Alabama 35203-2707
Telephone Number 205/326-2700
http://www.energen.com

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

Indicate by a check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YES XNO ____

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

Energen Corporation YES XNO ___

Alabama Gas Corporation YES___ NO X

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

Energen Corporation YESNO X

Alabama Gas Corporation YES NO X

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of November 2, 2005

Energen Corporation	$0.01 par value	73,283,545 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION
FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2005
TABLE OF CONTENTS
		Page
PART I: FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	(a) Consolidated Condensed Statements of Income of Energen Corporation	3
	(b) Consolidated Condensed Balance Sheets of Energen Corporation	4
	(c) Consolidated Condensed Statements of Cash Flows of Energen Corporation	6
	(d) Condensed Statements of Income of Alabama Gas Corporation	7
	(e) Condensed Balance Sheets of Alabama Gas Corporation	8
	(f) Condensed Statements of Cash Flows of Alabama Gas Corporation	10
	(g) Notes to Unaudited Condensed Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	22
	Selected Business Segment Data of Energen Corporation	30
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	32
Item 4.	Controls and Procedures	33
	PART II: OTHER INFORMATION
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 6.	Exhibits	34
SIGNATURES		35

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended		Nine months ended
	September 30,		September 30,
(in thousands, except per share data)	2005	2004	2005	2004
Operating Revenues
Oil and gas operations	$  126,260	$  104,181	$  363,567	$ 295,538
Natural gas distribution	64,421	62,162	429,746	410,108
Total operating revenues	190,681	166,343	793,313	705,646
Operating Expenses
Cost of gas	27,386	26,545	214,665	205,574
Operations and maintenance	67,818	60,780	195,127	170,126
Depreciation, depletion and amortization	34,215	30,849	98,741	88,418
Taxes, other than income taxes	19,523	15,343	65,867	55,647
Accretion expense	668	613	1,965	1,635
Total operating expenses	149,610	134,130	576,365	521,400
Operating Income	41,071	32,213	216,948	184,246
Other Income (Expense)
Interest expense	(11,600)	(10,515)	(34,794)	(31,527)
Other income	822	702	1,694	2,197
Other expense	(104)	(225)	(638)	(1,920)
Total other expense	(10,882)	(10,038)	(33,738)	(31,250)
Income From Continuing Operations Before Income Taxes	30,189	22,175	183,210	152,996
Income tax expense	11,116	8,498	67,619	56,943
Income From Continuing Operations	19,073	13,677	115,591	96,053
Discontinued Operations, net of taxes
Income (loss) from discontinued operations	3	55	(2)	147
Gain (loss) on disposal of discontinued operations	10	8	120	(5)
Income From Discontinued Operations	13	63	118	142
Net Income	$    19,086	$    13,740	$ 115,709	$    96,195
Diluted Earnings Per Average Common Share*
Continuing operations	$      0.26	$      0.19	$      1.57	$      1.31
Discontinued operations	-	-	-	-
Net Income	$        0.26	$        0.19	$        1.57	$        1.31
Basic Earnings Per Average Common Share*
Continuing operations	$      0.26	$      0.19	$      1.58	$      1.33
Discontinued operations	-	-	0.01	-
Net Income	$     0.26	$     0.19	$     1.59	$     1.33
Dividends Per Common Share*	$       0.10	$  0.09625	$     0.30	$  0.28125
Diluted Average Common Shares Outstanding*	73,878	73,401	73,725	73,258
Basic Average Common Shares Outstanding*	73,024	72,537	72,998	72,449

*Share and per share data have been restated to reflect a 2-for-1 stock split payable June 1, 2005 (see Note 15)

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

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	September 30, 2005	December 31, 2004
ASSETS
Current Assets
Cash and cash equivalents	$       38,233	$       4,489
Accounts receivable, net of allowance for doubtful     accounts of $10,774 at September 30, 2005, and     $10,472 at December 31, 2004	166,089	217,360
Inventories, at average cost
Storage gas inventory	74,062	51,093
Materials and supplies	7,462	7,843
Liquified natural gas in storage	3,043	3,688
Deferred income taxes	113,195	36,285
Prepayments and other	60,685	29,150
Total current assets	462,769	349,908
Property, Plant and Equipment
Oil and gas properties, successful efforts method	1,710,461	1,591,119
Less accumulated depreciation, depletion and amortization	444,915	381,734
Oil and gas properties, net	1,265,546	1,209,385
Utility plant	975,850	941,862
Less accumulated depreciation	379,071	373,589
Utility plant, net	596,779	568,273
Other property, net	6,114	5,401
Total property, plant and equipment, net	1,868,439	1,783,059
Other Assets
Regulatory asset	27,007	19,650
Deferred charges and other	33,982	29,122
Total other assets	60,989	48,772
TOTAL ASSETS	$   2,392,197	$   2,181,739

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

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands, except share and per share data)	September 30, 2005	December 31, 2004
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Long-term debt due within one year	$      15,000	$      10,000
Notes payable to banks	-	135,000
Accounts payable	369,319	159,871
Accrued taxes	34,882	34,541
Customers' deposits	19,331	19,549
Amounts due customers	11,654	10,363
Accrued wages and benefits	35,790	28,941
Regulatory liability	82,267	47,060
Other	50,556	53,293
Total current liabilities	618,799	498,618
Long-term debt	659,936	612,891
Deferred Credits and Other Liabilities
Asset retirement obligation	37,207	34,841
Minimum pension liability	28,769	14,216
Regulatory liability	117,932	111,928
Deferred income taxes	127,566	95,417
Other	48,213	10,162
Total deferred credits and other liabilities	359,687	266,564
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, 73,317,588 shares outstanding at September 30, 2005, and 73,165,958 shares outstanding at December 31, 2004	733	732
Premium on capital stock	387,810	380,965
Capital surplus	2,802	2,802
Retained earnings	553,357	459,626
Accumulated other comprehensive loss, net of tax
Unrealized loss on hedges	(172,879)	(25,466)
Minimum pension liability	(14,446)	(11,864)
Deferred compensation on restricted stock	(2,573)	(2,675)
Deferred compensation plan	11,830	28,919
Treasury stock, at cost* (1,068,594 shares at September 30, 2005, and 1,000,952 shares at December 31, 2004)	(12,859)	(29,373)
Total shareholders' equity	753,775	803,666
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$   2,392,197	$   2,181,739

*Share and per share data have been restated to reflect a 2-for-1 stock split payable June 1, 2005 (see Note 15)

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

CONSOLIDATEDCONDENSED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Nine months ended September 30,(in thousands)	2005	2004
Operating Activities
Net income	$     115,709	$     96,195
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization	98,769	88,559
Deferred income taxes	46,960	50,783
Deferred investment tax credits	-	(308)
Change in derivative fair value	22,476	4,213
Loss (gain) on sale of assets	(1,590)	182
Other, net	7,212	10,648
Net change in:
Accounts receivable, net	28,865	32,909
Inventories	(21,943)	(19,819)
Accounts payable	(13,700)	(16,826)
Amounts due customers	25,169	(5,413)
Other current assets and liabilities	4,799	12,107
Net cash provided by operating activities	312,726	253,230
Investing Activities
Additions to property, plant and equipment	(177,642)	(131,204)
Acquisitions, net of cash acquired	(5,457)	(263,818)
Proceeds from sale of assets	10,338	134
Other, net	(1,102)	(2,144)
Net cash used in investing activities	(173,863)	(397,032)
Financing Activities
Payment of dividends on common stock	(21,978)	(20,447)
Issuance of common stock	3,952	5,216
Purchase of treasury stock	(2,168)	(510)
Reduction of long-term debt	(28,060)	(40,073)
Proceeds from issuance of long-term debt	80,000	-
Debt issuance costs	(1,865)	-
Net change in short-term debt	(135,000)	202,000
Net cash provided by (used in) financing activities	(105,119)	146,186
Net change in cash and cash equivalents	33,744	2,384
Cash and cash equivalents at beginning of period	4,489	2,127
Cash and Cash Equivalents at End of Period	$      38,233	$       4,511

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

CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
	Three months ended		Nine months ended
	September 30,		September 30,
(in thousands)	2005	2004	2005	2004

Operating Revenues	$ 64,421	$ 62,162	$ 429,746	$ 410,108
Operating Expenses
Cost of gas	28,047	27,190	216,360	207,073
Operations and maintenance	30,898	29,563	90,986	88,422
Depreciation	10,668	9,985	31,724	29,453
Income taxes
Current	(9,788)	(9,604)	17,378	9,810
Deferred, net	4,351	4,800	2,181	7,878
Deferred investment tax credits, net	-	(84)	-	(308)
Taxes, other than income taxes	5,833	5,554	29,667	28,701
Total operating expenses	70,009	67,404	388,296	371,029
Operating Income (Expense)	(5,588)	(5,242)	41,450	39,079
Other Income (Expense)
Allowance for funds used during construction	195	347	568	1,008
Other income	372	426	1,069	1,527
Other expense	(104)	(248)	(629)	(1,934)
Total other income	463	525	1,008	601
Interest Charges
Interest on long-term debt	3,291	2,462	10,263	8,212
Other interest expense	394	566	928	2,335
Total interest charges	3,685	3,028	11,191	10,547
Net Income (Loss)	$ (8,810)	$ (7,745)	$ 31,267	$ 29,133

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

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	September 30, 2005	December 31, 2004
ASSETS
Property, Plant and Equipment
Utility plant	$    975,850	$    941,862
Less accumulated depreciation	379,071	373,589
Utility plant, net	596,779	568,273
Other property, net	170	325
Current Assets
Cash and cash equivalents	4,803	3,467
Accounts receivable
Gas	68,701	142,736
Other	16,124	11,952
Affiliated companies	-	2,190
Allowance for doubtful accounts	(10,000)	(9,600)
Inventories, at average cost
Storage gas inventory	74,062	51,093
Materials and supplies	4,141	4,281
Liquified natural gas in storage	3,043	3,688
Deferred income taxes	13,368	15,233
Regulatory asset	341	-
Prepayments and other	52,528	21,901
Total current assets	227,111	246,941
Other Assets
Regulatory asset	27,007	19,650
Deferred charges and other	5,661	4,558
Total other assets	32,668	24,208
TOTAL ASSETS	$    856,728	$    839,747

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

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands, except share data)	September 30, 2005	December 31, 2004
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 outstanding at        September 30, 2005 and December 31, 2004	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	232,812	223,515
Total common shareholder's equity	267,316	258,019
Long-term debt	186,390	129,450
Total capitalization	453,706	387,469
Current Liabilities
Long-term debt due within one year	5,000	10,000
Notes payable to banks	-	82,000
Accounts payable	58,730	81,591
Affiliated companies	6,565	-
Accrued taxes	30,630	27,410
Customers' deposits	19,331	19,549
Amounts due customers	11,654	10,363
Accrued wages and benefits	6,820	7,724
Regulatory liability	82,267	47,060
Other	11,043	11,906
Total current liabilities	232,040	297,603
Deferred Credits and Other Liabilities
Deferred income taxes	40,404	40,070
Minimum pension liability	9,010	-
Regulatory liability	117,932	111,928
Other	3,636	2,677
Total deferred credits and other liabilities	170,982	154,675
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION	$    856,728	$    839,747

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

CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Nine months ended September 30,(in thousands)	2005	2004
Operating Activities
Net income	$     31,267	$     29,133
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization	31,724	29,453
Deferred income taxes	2,181	7,878
Deferred investment tax credits	-	(308)
Other, net	1,430	6,414
Net change in:
Accounts receivable	47,857	53,790
Inventories	(22,184)	(18,702)
Accounts payable	(22,862)	(18,005)
Amounts due customers	25,169	(5,413)
Other current assets and liabilities	5,760	5,768
Net cash provided by operating activities	100,342	90,008
Investing Activities
Additions to property, plant and equipment	(52,921)	(40,991)
Other, net	(1,102)	(1,778)
Net cash used in investing activities	(54,023)	(42,769)
Financing Activities
Dividends	(21,970)	(20,426)
Reduction of long-term debt	(28,060)	(30,073)
Proceeds from issuance of long-term debt	80,000	-
Debt issuance costs	(1,708)	-
Net advances from (to) affiliates	8,755	(38,061)
Net change in short-term debt	(82,000)	44,000
Net cash used in financing activities	(44,983)	(44,560)
Net change in cash and cash equivalents	1,336	2,679
Cash and cash equivalents at beginning of period	3,467	1,440
Cash and Cash Equivalents at End of Period	$     4,803	$        4,119

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

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

1. BASIS OF PRESENTATION The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2004, 2003 and 2002 included in the 2004 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 o f 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 write-downs 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 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. During the quarter ended September 30, 2005, the Company reduced Treasury Stock and Deferred Compensation Plan, both reflected in shareholders' equity, by $25 million to correct the carrying value of the equity-based deferred compensation previously reported at market value to historical cost as prescribed by the Emerging Issues Task Force No. 97-14, "Accounting for Deferred Compensation Arrangements Where Amounts Earned Are Held in a Rabbi Trust and Invested."  This change had no impact on current or previously reported net income, cash flows or total shareholders' equity. STOCK-BASED COMPENSATION The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), "Accounting for Stock-Based Compensation," prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to six years. The cost related to stock-based employee compensation included in the determination of proforma net income for the three months and nine months ended September 30, 2005 and 2004, approximates that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123. The following table illustrates the effect on net income and diluted and basic earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period:
	Three months ended September 30,		Nine months ended September 30,
(in thousands)	2005	2004	2005	2004
Net income
As reported	$ 19,086	$ 13,740	$ 115,709	$ 96,195
Stock-based compensation expense included in reported net income, net of tax	3,077	1,853	6,769	4,397
Stock-based compensation expense determined under fair value based method, net of tax	(2,175)	(1,319)	(5,157)	(3,369)
Pro forma	$ 19,988	$ 14,274	$ 117,321	$ 97,223
Diluted earnings per average common share*
As reported	$ 0.26	$ 0.19	$ 1.57	$ 1.31
Pro forma	$ 0.27	$ 0.19	$ 1.59	$ 1.33
Basic earnings per average common share*
As reported	$ 0.26	$ 0.19	$ 1.59	$ 1.33
Pro forma	$ 0.27	$ 0.20	$ 1.61	$ 1.34
*Share and per share data have been restated to reflect a 2-for-1 stock split payable June 1, 2005 (see Note 15)

3. REGULATORY 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 votes to either modify or discontinue its operation. 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, subje ct to change in the event that the Commission, 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, 2005, Alagasco had a $3.3 million reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. Alagasco did not have a reduction in rates related to the return on average equity for the rate year ended 2004. A $12.3 million and an $11.2 million annual increase in revenues became effective December 1 , 2004 and 2003, 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. The increase in O&M expense per customer was above the index range for the rate year ended September 30, 2004; as a result, the utility returned $1.2 million pre-tax to customers through rate adjustments under the provisions of RSE. Alagasco's O&M expense fell within the index range for the rate year ended September 30, 2005. 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 certain limitations including regulatory limits on adjustments to increase customers' bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high 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. 4. DERIVATIVE COMMODITY INSTRUMENTS Energen Resources Corporation, Energen's oil and gas subsidiary, periodically enters into derivative commodity instruments that qualify as cash flow hedges under 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 the credit ratings must be maintained at investment grade status to have available counterparty credit. At September 30, 2005, the Company had $1.8 million posted in collateral payments with a certain counterparty. Energen Resources applies SFAS No. 133 which requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of equity and subsequently reclassified into earnings as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings 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 September 30, 2005, $148.1 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to operating revenues during the next 12-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 hedges as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. For the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, Energen Resources recorded a $1 million after-tax loss for the three months ended September 30, 2005, and a $3 million after-tax loss year-to-date. Also, Energen Resources recorded an after-tax loss of $11.1 million for the qu arter and a $16.7 million after-tax loss year-to-date on contracts that did not meet the definition of cash flow hedges under SFAS No. 133. As of September 30, 2005, the Company had 2.9 billion cubic feet (Bcf) of gas hedges with a fair value after-tax loss of $11.4 million which expire by year-end that did not meet the definition of a cash flow hedge but are considered by the Company to be viable economic hedges. In the current year-to-date, the Company discontinued hedge accounting and reclassified losses of $0.9 million after-tax from OCI into operating revenues when Energen Resources determined it was probable certain forecasted transactions volumes would not occur. The Company had $106 million and $15.6 million included in current and noncurrent deferred income taxes on the consolidated balance sheets related to items included in OCI as of September 30, 2005 and December 31, 2004, respectively. At September 30, 2005, and December 31, 2004, the Company had $270 million and $40.7 million, respectively, re corded in accounts payable and $40.3 million and $3.2 million, respectively, recorded in other noncurrent liabilities related to derivative liabilities.
Energen Resources has entered into the following transactions for the remainder of 2005 and subsequent years:
Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2005	5.7 Bcf	$6.15 Mcf	NYMEX Swaps
	6.9 Bcf	$5.11 Mcf	Basin Specific Swaps
2006	16.3 Bcf	$8.08 Mcf	NYMEX Swaps
	21.9 Bcf	$6.48 Mcf	Basin Specific Swaps
2007	3.0 Bcf	$9.72 Mcf	Basin Specific Swaps
Natural Gas Basis Differential
2005	1.1 Bcf	*	Basis Swaps
Oil
2005	397 MBbl	$33.96 Bbl	NYMEX Swaps
	240 MBbl	$33.21 Bbl	West Texas Sour Swaps
2006	2,424 MBbl	$51.61 Bbl	NYMEX Swaps
Oil Basis Differential
2005	237 MBbl	*	Basis Swaps
2006	1,915 MBbl	*	Basis Swaps
Natural Gas Liquids
2005	12.8 MMGal	$0.54 Gal	Liquids Swaps
2006	30.2 MMGal	$0.56 Gal	Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. 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. 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 Resourc es has hedged exposures to the variability of cash flows is through December 31, 2007.

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," Alagasco recorded a $41.8 million and $8.1 million gain as a regulatory liability as of September 30, 2005 and December 31, 2004, respectively, with a corresponding asset in prepayments and other representing the fair value of derivatives.

5. RECONCILIATION OF EARNINGS PER SHARE

		Three months ended				Three months ended
(in thousands, except per share amounts)		September 30, 2005				September 30, 2004
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount
Basic EPS*	$   19,086		73,024	$    0.26	$ 13,740		72,537	$ 0.19
Effect of Dilutive Securities
Long-range performance shares			378				311
Stock options			345				509
Restricted stock			131				44
Diluted EPS*	$   19,086		73,878	$    0.26	$ 13,740		73,401	$ 0.19

		Nine months ended				Nine months ended
(in thousands, except per share amounts)		September 30, 2005				September 30, 2004
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount
Basic EPS*	$ 115,709		72,998	$    1.59	$   96,195		72,449	$    1.33
Effect of Dilutive Securities
Long-range performance shares			320				284
Stock options			304				463
Restricted stock			103				62
Diluted EPS*	$ 115,709		73,725	$    1.57	$   96,195		73,258	$    1.31

*Share and per share data have been restated to reflect a 2-for-1 stock split payable June 1, 2005 (see Note 15)

For the three months and nine months ended September 30, 2005 and 2004, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

6. SEGMENT INFORMATION The Company principally is engaged in two business segments: the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution) and the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations).
	Three months ended		Nine months ended
	September 30,		September 30,
(in thousands)	2005	2004	2005	2004
Operating revenues from continuing operations
Oil and gas operations	$ 126,921	$ 104,826	$ 365,262	$ 297,037
Natural gas distribution	64,421	62,162	429,746	410,108
Eliminations and other	(661)	(645)	(1,695)	(1,499)
Total	$ 190,681	$ 166,343	$ 793,313	$ 705,646
Operating income (loss) from continuing operations
Oil and gas operations	$ 52,368	$ 42,584	$ 156,713	$ 128,321
Natural gas distribution	(11,025)	(10,130)	61,009	56,459
Eliminations and corporate expenses	(272)	(241)	(774)	(534)
Total	$ 41,071	$ 32,213	$ 216,948	$ 184,246
Other income (expense)
Oil and gas operations	$ (7,869)	$ (7,607)	$ (24,017)	$ (21,385)
Natural gas distribution	(3,222)	(2,503)	(10,183)	(9,946)
Eliminations and other	209	72	462	81
Total	$ (10,882)	$ (10,038)	$ (33,738)	$ (31,250)
Income from continuing operations before income taxes	$ 30,189	$ 22,175	$ 183,210	$ 152,996

(in thousands)	September 30, 2005	December 31, 2004
Identifiable assets
Oil and gas operations	$   1,470,756	$   1,315,967
Natural gas distribution	856,728	837,557
Subtotal	2,327,484	2,153,524
Eliminations and other	64,713	28,215
Total	$2,392,197	$  2,181,739

7. COMPREHENSIVE INCOME (LOSS) Comprehensive income (loss) consisted of the following:
	Three months ended	Three months ended
(in thousands)	September 30, 2005	September 30, 2004
Net Income	$   19,086	$    13,740
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($82.9) million and ($23.6) million	(135,263)	(38,585)
Reclassification adjustment for losses realized in net income, net of tax of $17 million and $8.2 million	27,680	13,307
Minimum pension liability, net of tax of ($1.4) million and ($0.7) million	(2,582)	(1,356)
Comprehensive Loss	$   (91,079)	$   (12,894)

	Nine months ended	Nine months ended
(in thousands)	September 30, 2005	September 30, 2004
Net Income	$  115,709	$    96,195
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($122.5) million and ($46.4) million	(199,829)	(76,623)
Reclassification adjustment for losses realized in net income, net of tax of $32.1 million and $19.8 million	52,416	32,227
Minimum pension liability, net of tax of ($1.4) million and ($0.7) million	(2,582)	(1,356)
Comprehensive Income (Loss)	$   (34,286)	$     50,443

Accumulated other comprehensive loss consisted of the following:
(in thousands)	September 30, 2005		December 31, 2004
Unrealized loss on hedges, net of tax of ($106) million and ($15.6) million	$    (172,879)		$    (25,466)
Minimum pension liability, net of tax of ($7.8) million and ($6.4) million	(14,446)		(11,864)
Accumulated Other Comprehensive Loss	$    (187,325)		$    (37,330)
8. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS 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 write-downs 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 o f the carrying amount or fair value. In the nine months ended September 30, 2005, Energen Resources recorded a pre-tax gain of $194,000 primarily from a property sale located in the Permian Basin. Energen Resources had no property sales during the three months ended September 30, 2005 and 2004 or the year-to-date ended September 30, 2004. The following are the results of operations from discontinued operations:
	Three months ended			Nine months ended
	September 30,			September 30,
(in thousands, except per share data)	2005	2004		2005	2004
Oil and gas revenues	$ -	$ 156		$ 47	$ 428
Pretax income (loss) from discontinued operations	$ 5	$ 90		$ (3)	$ 237
Income tax expense (benefit)	2	35		(1)	90
Income (Loss) From Discontinued Operations	3	55		(2)	147
Gain (loss) on disposal of discontinued operations	16	13		194	(8)
Income tax expense (benefit)	6	5		74	(3)
Gain (Loss) on Disposal of Discontinued Operations	10	8		120	(5)
Total Income From Discontinued Operations	$ 13	$ 63		$ 118	$ 142
Diluted Earnings Per Average Common Share*
Income from Discontinued Operations	$ -	$ -		$ -	$ -
Loss on Disposal of Discontinued Operations	-	-		-	-
Total Income from Discontinued Operations	$ -	$ -		$ -	$ -
Basic Earnings Per Average Common Share*
Income from Discontinued Operations	$ -	$ -		$ -	$ -
Loss on Disposal of Discontinued Operations	-	-		0.01	-
Total Income from Discontinued Operations	$ -	$ -		$ 0.01		$ -

*Share and per share data have been restated to reflect a 2-for-1 stock split payable June 1, 2005 (see Note 15)

9. EMPLOYEE BENEFIT PLANS

The components of net pension expense for the Company's two defined benefit non-contributory pension plans were:

(in thousands)	Plan A		Plan B
	Three Months Ended September 30,		Three Months Ended September 30,
	2005	2004	2005	2004
Components of net periodic benefit cost:
Service cost	$ 1,544	$ 1,356	$ 155	$ 146
Interest cost	1,886	1,664	351	346
Expected long-term return on assets	(2,199)	(1,950)	(540)	(522)
Actuarial loss	687	433	31	27
Prior service cost amortization	59	58	94	88
Net periodic expense	$ 1,977	$ 1,561	$ 91	$ 85

(in thousands)	Plan A		Plan B
	Nine months Ended September 30,		Nine months Ended September 30,
	2005	2004	2005	2004
Components of net periodic benefit cost:
Service cost	$ 4,633	$ 4,068	$ 464	$ 438
Interest cost	5,659	4,992	1,054	1,038
Expected long-term return on assets	(6,597)	(5,850)	(1,619)	(1,566)
Actuarial loss	2,061	1,299	283	81
Prior service cost amortization	176	174	92	264
Net periodic expense	$ 5,932	$ 4,683	$ 274	$ 255
The Company is not required to make pension contributions in 2005. The Company will reevaluate discretionary contributions in the fourth quarter of 2005 based on the annual measurement of pension obligations.

The components of net periodic post-retirement benefit expense for the Company's post-retirement benefit plans

were:

(in thousands)	Salaried Employees		Union Employees
	Three Months Ended September 30,		Three Months Ended September 30,
	2005	2004	2005	2004
Components of net periodic benefit cost:
Service cost	$ 231	$ 349	$ 124	$ 130
Interest cost	492	572	515	463
Expected long-term return on assets	(425)	(433)	(658)	(699)
Actuarial gain	(32)	-	(36)	(134)
Prior service cost amortization	-	-	1	1
Transition amortization	171	171	321	321
Net periodic expense	$ 437	$ 659	$ 267	$ 82

(in thousands)	Salaried Employees		Union Employees
	Nine months Ended September 30,		Nine months Ended September 30,
	2005	2004	2005	2004
Components of net periodic benefit cost:
Service cost	$ 694	$ 990	$ 373	$ 368
Interest cost	1,477	1,732	1,546	1,450
Expected long-term return on assets	(1,277)	(1,194)	(1,975)	(1,928)
Actuarial gain	(96)	-	(110)	(280)
Prior service cost amortization	-	-	3	3
Transition amortization	512	512	964	963
Net periodic expense	$ 1,310	$ 2,040	$ 801	$ 576

For the three months and nine months ended September 30, 2005, the Company made contributions aggregating $0.8 million and $2.4 million, respectively, to the post-retirement plans. The Company expects to make additional discretionary contributions of approximately $0.8 million through the remainder of 2005.

10. COMMITMENTS AND CONTINGENCIES Commitments and Agreements: Certain of Alagasco's long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $228 million through October 2013. 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 173.1 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. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers' current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2005, the fixed price purchases under these guarantees had a maximum term outstanding through March 2006 and an aggregate purchase price of $2.9 million with a market value of $6.1 million. Legal Matters:Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards may bear little or no relation to culpability or actual damages, thus making it increasingly difficult to predict litigation results. In January 2005, a lawsuit was tried in Cochran County, Texas in which the plaintiff alleged preferential purchase right claims against Energen Resources with respect to certain properties acquired by Energen Resources in 2002. The jury rendered a verdict in Energen Resources' favor on all counts. Subsequently, in March 2005, the Judge issued a decision overruling the jury verdict. Energen Resources is pursuing an appeal of the Judge's order and expects to prevail. Under the Judge's order, Energen Resources potential pre-tax charge to income would be approximately $2.3 million as of September 30, 2005, none of which has been accrued. This amount includes the net cash flows attributable to the property since its acquisition. Alagasco is a defendant in a lawsuit filed in Jefferson County, Alabama alleging breach of contract and fraud for compensatory and punitive damages in connection with compressed natural gas vehicle services provided to Alagasco by the plaintiff. Alagasco expects to prevail in its defense of the case. As noted above, however, it is difficult to predict litigation results. In the event that the plaintiff prevails, Alagasco estimates a damage award range of $300,000 to $2,000,000, none of which has been accrued. Various other pending or threatened legal proceedings arising in the normal course of business are in progress currently, and the Company has accrued a provision for estimated costs. 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. During 2004, the State of New Mexico issued new regulations related to below-grade storage pits. Such pits are used to temporarily hold produced fluids until they can be disposed of permanently. Under the new regulations, the storage pits must be constructed with secondary containment and leak detection, and all such pits will require an annual certification attesting that the storage pits do not leak. As a result of this regulation, the Company expensed $0.9 million as a lease operating expense during the nine months ended September 30, 2005. During 2004, the Company capitalized $0.5 million as part of its acquisition of properties in the San Juan Basin and expensed $1.6 million as a lease operating expense under this regulation. The Company does not anticipate any further remediation charges on existing properties related to the new regulations. 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 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, results of operations or cash flows of Alagasco.
11. REGULATORY ASSETS AND LIABILITIES The following table details regulatory assets and liabilities on the balance sheets:
(in thousands)	September 30, 2005		December 31, 2004
	Current	Noncurrent	Current	Noncurrent
Regulatory assets:
Pension asset	$   -	$    26,475	$     -	$     19,650
Other	341	532	-	-
Total regulatory assets	$   341	$    27,007	$     -	$    19,650
Regulatory liabilities:
Enhanced stability reserve	$    3,671	$     -	$    3,671	$       -
Gas supply adjustment	28,694	-	6,964	-
Risk management activities	41,832	-	8,097	-
RSE adjustment	3,399	-	1,251	-
Unbilled service margin	4,671	-	27,077	-
Asset removal costs, net	-	116,962	-	110,912
Other	-	970	-	1,016
Total regulatory liabilities	$     82,267	$  117,932	$    47,060	$   111,928
12. EQUITY AND DEBT OFFERINGS In November 2004, Energen issued $100 million of Floating Rate Senior Notes (Senior Notes) due November 15, 2007. The interest rate is the three-month LIBOR Rate plus .35%, reset quarterly. At September 30, 2005, the interest rate was 4.14 percent on the Senior Notes. In January 2005, Alagasco issued $40 million of long-term debt with an interest rate of 5.2 percent due January 15, 2020 and $40 million of long-term debt with an interest rate of 5.7 percent due January 15, 2035. The Senior Note proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources. Alagasco used long-term debt proceeds to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance $30 million of Medium-Term Notes called by Alagasco in April 2004. In August 2005, Alagasco called a total of $18 million of Medium-Term Notes maturing June 27, 2007 to July 5, 2022. As of September 30, 2005, Energen and Alagasco had short-term credit lines available for working capital needs up to $260 million. Alagasco has been authorized by the APSC to borrow up to a total of $100 million of these available short-term credit lines. 13. RECENT ACCOUNTING PRONOUNCEMENTS In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), "Share-Based Payment (SFAS No. 123R)," which requires a fair value base method of accounting using pricing models that reflect the specific economics of a company's transactions. This statement is effective for the first annual reporting period beginning after June 15, 2005. The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 (as amended), which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation effective January 1, 2003. The Company will adopt SFAS No. 123R using the modified prospective application method for new awards effective January 1, 2006. The Company is currently evaluating its stock-based compensation and the application of SFAS No. 123R. In December 2004, the FASB issued FSP No. 109-1, "Application of SFAS No. 109, Accounting for Income Taxes, to the provision within the American Jobs Creation Act of 2004 (the Act) that provides a tax deduction on qualified production activities." This Act includes a tax deduction of up to 9 percent (when fully phased-in) of the lesser of (a) qualified production activities income as defined in the Act, or (b) taxable income of the Company determined without regard to this deduction. This tax deduction would apply to qualified production activities of Energen Resources and would be limited to 50 percent of W-2 wages paid by the Company. Pursuant to FSP No. 109-1, the deduction will be reported in the period in which the deduction is claimed on the Company's tax return and will not have an effect on deferred tax assets or deferred tax liabilities. The Company estimates the impact of this tax legislation will reduce income tax expense by approximately $0.9 million during 2005. In March 2005, the FASB issued FIN No. 47, "Accounting for Conditional Asset Retirement Obligations", which refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. The impact of this interpretation on the Company is currently being evaluated.
14. ACQUISITION OF OIL AND GAS PROPERTIES On August 2, 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $273 million. The effective date of the acquisition was August 1, 2004. Energen Resources acquired an estimated 245 Bcfe of proved natural gas and natural gas liquids reserves. Approximately 51 percent of the proved reserves were estimated to be behind pipe and undeveloped. The Company estimates approximately 80 percent of the acquisition reserves are gas with natural gas liquids comprising the balance. Energen used its short-term credit facilities and internally generated cash flows to finance the acquisition. A portion of the short-term debt incurred to finance the acquisition was repaid when Energen issued $100 million of Floating Rate Senior Notes in November 2004. Summarized below are the consolidated results of operations for the three months and nine months ended September 30, 2004, on an unaudited pro forma basis as if the purchase of assets had occurred at the beginning of the period presented. The pro forma information is based on the Company's consolidated results of operations for the three months and nine months ended September 30, 2004, and on the data provided by the seller. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor are they indicative of results of the future operations of the combined enterprises.

	Three months ended	Nine months ended
(in thousands, except per share data)	September 30, 2004	September 30, 2004
Operating revenues	$ 168,107	$ 717,992
Income from continuing operations	$ 13,792	$ 96,857
Net income	$ 13,855	$ 96,999
Diluted earnings per average common share*	$ 0.19	$ 1.32
Basic earnings per average common share*	$ 0.19	$ 1.34
*Shareand per share data have been restated to reflect a 2-for-1 stock split payable June 1, 2005 (see Note 15)
15. STOCK DIVIDEND On April 27, 2005, Energen's shareholders approved a 2-for-1 split of the Company's common stock. The split was effected in the form of a 100 percent stock dividend and was payable on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split. Effective April 29, 2005, the Restated Certificate of Incorporation of Energen Corporation was amended to increase the Company's authorized common stock, par value $0.01 per share, from 75,000,000 shares to 150,000,000 shares.

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

Energen's net income totaled $19.1 million ($0.26 per diluted share) for the three months ended September 30, 2005 and compared favorably with net income of $13.7 million ($0.19 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended September 30, 2005, of $28.1 million compared with $21.7 million in the same quarter in the previous year. Energen Resources reported net income from continuing operations of $28.1 million in the current quarter as compared with $21.6 million in the same quarter last year. Significantly higher commodity prices (approximately $10 million after-tax) and increased production volumes (approximately $3 million after-tax) were partially offset by increased lease operating expenses (approximately $3 million after-tax), higher production taxes (approximately $2 million after-tax) and increased depreciation, depletion and amortization (DD&A) expense (approxi mately $2 million after-tax). Energen's natural gas utility, Alagasco, reported a net loss of $8.8 million in the third quarter of 2005 compared to a net loss of $7.7 million in the same period last year. Alagasco recognized a reduction in revenues in the current quarter to bring the return on average equity to midpoint within the utility's allowed range of return at the end of the fiscal year for rate-setting purposes (approximately $2 million after-tax). 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 2005 year-to-date, Energen's net income totaled $115.7 million ($1.57 per diluted share) and compared favorably to net income of $96.2 million ($1.31 per diluted share) for the same period in the prior year. Energen Resources had net income for the nine months ended September 30, 2005, of $84 million as compared with $66.7 million in the previous period. Energen Resources generated income from continuing operations of $83.9 million in the current year-to-date as compared with $66.6 million in the same period last year primarily as a result of higher commodity prices (approximately $31 million after-tax) and increased production volumes (approximately $11 million after-tax) partially offset by the impact of increased lease operating expenses (approximately $11 million after-tax), higher production taxes (approximately $6 million after-tax), increased DD&A expense (approximately $5 million after-tax) and increased administrative expenses (approximately $4 million after-tax). Alag asco's net income of $31.3 million in the current year-to-date increased from net income of $29.1 million in the same period in the previous year primarily reflecting the utility's ability to earn on a higher level of equity.

Oil and Gas Operations

Revenues from oil and gas operations rose 21.2 percent to $126.3 million for the three months ended September 30, 2005, and 23 percent to $363.6 million in the year-to-date largely as a result of increased commodity prices as well as the impact of higher gas production volumes. During the current quarter, average gas prices rose 11.5 percent to $5.31 per thousand cubic feet (Mcf), while average oil prices increased 23.5 percent to $35.51 per barrel. Natural gas liquids prices increased 18 percent to an average price of $0.59 per gallon. In the year-to-date, average gas prices increased 13.1 percent to $5.39 Mcf, average oil prices rose 22.9 percent to $33.75 per barrel and natural gas liquids prices increased 22.7 percent to $0.54 per gallon. The average sales prices included an $8.6 million after-tax loss in the current quarter and an $11.4 million after-tax loss year-to-date from the effects of open gas derivative contracts marked-to-market. These gas contracts did not meet the defin ition of cash flow hedges, as more fully described below. The Company also included in the average gas and oil sales prices a $0.9 million after-tax loss for the current quarter and a $1.5 million after-tax loss year-to-date on open contracts for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges.

Production increased primarily due to volumes related to the prior year purchase of San Juan Basin coalbed methane properties and increased drilling of wells in North Louisiana. Energen Resources acquired an estimated 245 Bcfe of proved natural gas and natural gas liquids reserves in the San Juan Basin effective August 1, 2004. Negatively affecting production was a normal production decline that was in excess of new production coming on-line in the Permian Basin. Natural gas production from continuing operations in the third quarter rose 9.4 percent to 16 billion cubic feet (Bcf), while oil volumes fell 4.8 percent to 813 thousand barrels (MBbl) and natural gas liquids production declined slightly to 18.1 million gallons (MMgal). For the year-to-date, natural gas production increased 9.1 percent to 45.9 Bcf and oil production decreased 3 percent to 2.5 MBbl. Natural gas liquids production rose 4.4 percent to 52.5 MMgal. Natural gas comprised approximately 65 percent of Energen Resources' p roduction for the current quarter and the year-to-date.

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 on oil, natural gas and natural gas liquids production. 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. These hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions.

Energen Resources applies SFAS No. 133 which requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of equity and subsequently reclassified into earnings as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings 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. Energen Resources recorded an after-tax loss of $11.1 million for the three month s ended September 30, 2005, and a $16.7 million after-tax loss year-to-date on open and closed contracts that did not meet the definition of cash flow hedges under SFAS No. 133. For the three months ended September 30, 2005, the Company recorded a $1 million after-tax loss and a $3 million after-tax loss year-to-date on open and closed contracts for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges.

Energen Resources has entered into the following transactions for the remainder of 2005 and subsequent years:
Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2005	5.7 Bcf	$6.15 Mcf	NYMEX Swaps
	6.9 Bcf	$5.11 Mcf	Basin Specific Swaps
2006	16.3 Bcf	$8.08 Mcf	NYMEX Swaps
	21.9 Bcf	$6.48 Mcf	Basin Specific Swaps
2007	3.0 Bcf	$9.72 Mcf	Basin Specific Swaps
Natural Gas Basis Differential
2005	1.1 Bcf	*	Basis Swaps
Oil
2005	397 MBbl	$33.96 Bbl	NYMEX Swaps
	240 MBbl	$33.21 Bbl	West Texas Sour Swaps
2006	2,424 MBbl	$51.61 Bbl	NYMEX Swaps
Oil Basis Differential
2005	237 MBbl	*	Basis Swaps
2006	1,915 MBbl	*	Basis Swaps
Natural Gas Liquids
2005	12.8 MMGal	$0.54 Gal	Liquids Swaps
2006	30.2 MMGal	$0.56 Gal	Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

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

Operations and maintenance (O&M) expense increased $5.7 million for the quarter and $22.2 million in the year-to-date. Lease operating expenses (excluding production taxes) increased by $5.3 million for the quarter and $17.2 million year-to-date primarily due to increased workover and maintenance expenses, increased ad valorem taxes and overall price increases related to higher commodity prices. Partially offsetting these increases were lower compliance costs related to prior year regulations for below-grade storage pits. Administrative expense rose $2.1 million for the three months ended September 30, 2005 and $6.3 million in the year-to-date, primarily due to labor related costs. Exploration expense was lower by $1.7 million in the third quarter and by $1.3 million in year-to-date comparisons.

Energen Resources' DD&A expense for the quarter increased $2.7 million and rose $8.1 million year-to-date. The average depletion rate for the current quarter was $0.98 per mcfe as compared to $0.91 per mcfe in the same period a year ago. For the nine months ended September 30, 2005, the average depletion rate was $0.96 per mcfe as compared to $0.89 per mcfe in the previous period. The increases in depletion rates were largely due to a higher depreciation rate on coalbed methane properties purchased in the prior year and to the current year production mix that reflects a higher percentage of the Company's shorter-lived North Louisiana/East Texas production.

Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $3.9 million higher this quarter and $9.3 million higher year-to-date largely due to increased commodity market prices and increased production related to the prior year San Juan Basin acquisition.

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 write-down of 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." In the current year-to-date, Energen Resources recorded a pre-tax gain of $194,000 primarily from a property sale located in the Permian Basin. Energen Resources had no property sales during the three months ended September 30, 2005 and 2004 or the year-to-date ended September 30, 2004.

Natural Gas Distribution

Natural gas distribution revenues increased $2.3 million for the quarter largely due to an increase in sales to commercial and industrial customers. Alagasco recognized a $3.3 million reduction in revenues in the current quarter under regulatory rate setting requirements to bring the return on average equity to midpoint in the allowed range of return. For the quarter, weather was comparable with the same period last year. Residential sales volumes declined 3.4 percent. Commercial and industrial customer sales volumes increased 14.1 percent primarily due to additional usage from co-generation plants along with increased volumes generated from new load. Transportation volumes decreased 6.6 percent in period comparisons. Revenues for the year-to-date rose $19.6 million primarily due to an increase in commodity gas costs partially offset by a decrease in weather related usage and the regulatory reduction to revenues as discussed for the quarter. Weather that was 7.8 percent warmer than in the previous period contributed to an 8.4 percent decline in residential sales volumes and a 3.5 percent decrease in commercial and industrial customer sales volumes. Large transportation volumes declined 7.2 percent. Increased gas purchase volumes resulted in a 3.2 percent increase in cost of gas for the quarter. For the year-to-date, an increase in cost of gas of 4.5 percent was largely due to higher gas costs compared to the prior period partially offset by a decline in gas purchase volumes. 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 3 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 votes to either modify or discontinue its operation.

O&M expense increased 4.5 percent in the current quarter and 2.9 percent in the nine months ended September 30, 2005, primarily due to increased bad debt expense and distribution maintenance expenses partially offset by reduced insurance costs. A 6.8 percent increase in depreciation expense in the current quarter and a 7.7 percent increase in the year-to-date was due to normal replacement of the utility's distribution and support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company increased $1.1 million in the third quarter and $3.3 million year-to-date primarily due to the issuance of $100 million of Floating Rate Senior Notes by Energen in November 2004 as well as Alagasco's issuance of $80 million of long-term debt in January 2005. Positively impacting interest expense was Alagasco's election to call $18 million of Medium-Term Notes in August 2005. In the year-to-date comparison, interest expense was also affected by $30 million of Medium-Term Notes that were called in April 2004 by Alagasco. In the current quarter, income tax expense for the Company increased $2.6 million and was $10.7 million higher in year-to-date comparisons largely due to higher consolidated pre-tax income. Alagasco's income tax benefit increased $0.5 million in the current quarter primarily due to a higher pre-tax loss. For the year-to-date comparison, income tax expense rose $2.2 million primarily due to higher pre-tax income.

Exposure to Natural Disaster

The Company's production properties and distribution system did not suffer significant damage from Hurricanes Katrina and Rita which occurred in the third quarter of 2005. Energen Resources experienced minimal loss of production and Alagasco had no significant supply disruptions as a result of these hurricanes. These events, however, highlight the potential for a period of production shut-in for Energen Resources resulting from a prolonged interruption of service in areas which have a concentration of fractionation plants and refineries through which a substantial portion of the Company's oil and natural gas liquids production flow. Alagasco's customer base is geographically concentrated in central Alabama. Damage to Alagasco's delivery infrastructure, Energen Resources' production infrastructure or to third party facilities which serve Alagasco and/or Energen Resources due to a natural disaster or other event could result in significant adverse financial consequences to Alagasco and/o r the Company.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $312.7 million as compared to $253.2 million. Operating cash flow benefited from higher realized commodity prices and production volumes at Energen Resources. The Company's working capital needs were also highly influenced by throughput, changes in weather, and timing of payments. Working capital needs at Alagasco were primarily affected by increased gas costs compared to the prior period and storage gas inventory.

The Company had a net outflow of cash from investing activities of $173.9 million for the nine months ended September 30, 2005 primarily due to additions of property, plant and equipment. Energen Resources invested $132.7 million in capital expenditures primarily related to the development of oil and gas properties. Utility capital expenditures totaled $52.9 million in the year-to-date and primarily represented system distribution expansion and support facilities.

The Company used $105.1 million for financing activities in the year-to-date primarily due to the repayment of short-term borrowings, repayments of long-term debt, including Alagasco's election to call $18 million of Medium-Term Notes in July 2005, and dividends paid to common stockholders. Also influencing financing activities were the proceeds from the issuance of $80 million of long-term debt by Alagasco in January 2005.

FUTURE CAPITAL RESOURCES AND LIQUIDITY

The Company plans to continue to implement its diversified growth strategy that focuses on expanding Energen Resources' oil and gas operations through the acquisition of producing properties with developmental potential while maintaining the strength of the Company's utility foundation. For the five years ended December 31, 2004, Energen's diluted EPS grew at an average compound rate of 17.5 percent a year. Over the long-term, Energen is targeting an average diluted EPS growth rate over each rolling five-year period of approximately 8 percent a year.

On April 27, 2005, Energen's shareholders approved a 2-for-1 split of the Company's common stock. The split was effected in the form of a 100 percent stock dividend and was payable on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split.

Over the five-year planning period ending December 31, 2009, Energen Resources plans to spend approximately $324 million for development on existing properties and $30 million for exploratory and other activities. Notwithstanding the estimated expenditures mentioned above, as an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen's acquisition criteria which could result in capital expenditures different than those outlined above. The Company is prepared to invest approximately $1 billion over the next five years for property acquisitions that meet Energen's acquisition criteria. To finance Energen Resources' investment program, the Company expects primarily to utilize short-term credit facilities to supplement internally generated cash flow. The Company may also periodically issue long-term debt and equity to replace short-term obligations, enhance li quidity and provide for permanent financing. Energen currently has available short-term credit facilities aggregating $260 million to help finance its growth plans and operating needs. Energen Resources' continued ability to invest in property acquisitions is subject to market conditions and industry trends.

In 2005, Energen Resources plans to invest approximately $168 million in capital expenditures primarily for development and exploratory activities. As of December 31, 2004, the estimated amount of 2005 development of previously identified proved undeveloped reserves was approximately $84 million. Approximately $5 million is estimated for 2005 exploratory exposure. Capital investment at Energen Resources in 2006 is expected to approximate $121 million for development and exploration. Of this $121 million, development of previously identified proved undeveloped reserves is estimated to be $30 million and exploratory exposure is estimated to be $6 million.

Energen Resources currently expects production to approximate 92 Bcfe and 89 Bcfe for 2005 and 2006, respectively. The Company's most recent estimate of production attributable to already owned proved reserves was prepared as of December 31, 2004. Production from proved reserves owned as of December 31, 2004, was estimated as 91 Bcfe and 88 Bcfe for 2005 and 2006, respectively.

Energen Resources' lease operating expenses have significantly increased reflecting higher workover and maintenance expenses, increased taxes and other field-service-related expenses generally caused by an increased price environment. In addition, wider than anticipated basis differentials have resulted from regional supply-and-demand. The Company anticipates these price increase trends will continue in the near term.

An increase in national wholesale natural gas prices will increase natural gas costs for Alagasco customers for the 2005-2006 heating season as compared to the 2004-2005 heating season. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment rider which permits the pass-through to customers for changes in the cost of gas supply. On October 1, 2005, Alagasco increased its rates 36.7 percent to begin recovering these increased gas costs although such increases will not have a significant impact on most customers until the winter heating season. Sustained high prices may decrease Alagasco's customer base and could result in a decline in 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 its evaluation of its receivables which are impacted by natural gas prices.

Alagasco maintains an investment in storage gas that is expected to average approximately $55 million in 2005 but will vary depending upon the price of natural gas. During 2005 and 2006, Alagasco plans to invest $69 million and $63 million, respectively, in utility capital expenditures for normal distribution and support systems. Over the Company's five-year planning period ending December 31, 2009, Alagasco anticipates capital investments of approximately $327 million. The utility anticipates funding these capital requirements through internally generated capital and the utilization of credit facilities. In January 2005, Alagasco issued $80 million in long-term debt to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance $30 million of Medium-Term Notes recalled by Alagasco in April 2004. In August 2005, Alagasco called $18 million of Medium-Term Notes maturing June 27, 2007 to July 5, 2022. During the fourth quarter of 2005, Alagasco plans to issu e $80 million in long-term debt in part to refinance the $18 million of called Medium-Term Notes. A portion of the proceeds is also expected to be used to refinance $56.7 million of notes scheduled to be called subsequent to the fourth quarter debt issuance by Alagasco.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include 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 the credit ratings must be maintained at investment grade status t o have available counterparty credit. At September 30, 2005, the Company had $1.8 million posted in collateral payments with a certain counterparty.

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. 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.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes the Company's significant contractual cash obligations, other than hedging contracts as of September 30, 2005.

	Payments Due before December 31,
(in thousands)	Total	2005	2006 & 2007	2008 & 2009	2010 & Thereafter
Short-term debt	$ -	$ -	$ -	$ -	$ -
Long-term debt(1)	676,390	-	115,000	10,000	551,390
Interest payments on debt(2)	486,270	9,661	75,158	66,435	335,016
Purchase obligations(3)	227,898	13,887	99,888	85,006	29,117
Capital lease obligations	-	-	-	-	-
Operating leases	50,055	957	7,399	6,409	35,290
Total contractual cash obligations	$ 1,440,613	$ 24,505	$ 297,445	$ 167,850	$ 950,813

(1) Long-term cash obligations include $1.5 million of unamortized debt discounts as of September 30, 2005. (2) Includes interest on fixed rate debt and an estimate of adjustable rate debt. The adjustable rate interest is calculated based on the indexed rate in effect at September 30, 2005. (3) Certain of the Company's long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $228 million through October 2013. The Company 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 173.1 Bcf through April 2015. Energen Resources operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement. The Company has two defined non-contributory pension plans and provides certain post-retirement healthcare and life insurance benefits. The Company is not required to make any funding payments during 2005 for the pension plans. The Company will reevaluate discretionary contributions in the fourth quarter of 2005 based on the annual measurement of pension obligations. The Company expects to make discretionary payments of $0.8 million to post-retirement benefit program assets during the remainder of 2005. Recent Accounting Pronouncements In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), "Share-Based Payment (SFAS No. 123R)," which requires a fair value base method of accounting using pricing models that reflect the specific economics of a company's transactions. This statement is effective for the first annual reporting period beginning after June 15, 2005. The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 (as amended), which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation effective January 1, 2003. The Company will adopt SFAS No. 123R using the modified prospective application method for new awards effective January 1, 2006. The Company is currently evaluating its stock-based compensation and the application of SFAS No. 123R. In December 2004, the FASB issued FSP No. 109-1, "Application of SFAS No. 109, Accounting for Income Taxes, to the provision within the American Jobs Creation Act of 2004 (the Act) that provides a tax deduction on qualified production activities." This Act includes a tax deduction of up to 9 percent (when fully phased-in) of the lesser of (a) qualified production activities income as defined in the Act, or (b) taxable income of the Company determined without regard to this deduction. This tax deduction would apply to qualified production activities of Energen Resources and would be limited to 50 percent of W-2 wages paid by the Company. Pursuant to FSP No. 109-1, the deduction will be reported in the period in which the deduction is claimed on the Company's tax return and will not have an effect on deferred tax assets or deferred tax liabilities. The Company estimates the impact of this tax legislation will reduce income tax expense by approximately $0.9 million during 2005. In March 2005, the FASB issued FIN No. 47, "Accounting for Conditional Asset Retirement Obligations", which refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. This interpretation is effective no later than the end of fiscal years ending after December 15, 2005. The impact of this interpretation on the Company is currently being evaluated. Forward-Looking Statements and Risk Factors Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the 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, our ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict. Third Party Facilities:The forward looking statements also assume generally uninterrupted access to third party oil and gas gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to 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 acquisition, development and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns, and these risks can be affected by lease and rig availability, complex geology and other factors. Energen Resources Hedging:Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate price risk, fluctuations in future commodity prices could materially affect the Company's financial position and results of operations and cash flows; furthermore, such risk mitigation activities may cause the Company's financial position and results of operations to be materially different from results that would have been obtained had such risk mitigation activities not occurred. The effectiveness of such risk-mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps 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 expo sed 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 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 our operations and substantial losses to the Company. In accordance with customary industry practices we maintain 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 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.
SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
		Three months ended		Nine months ended
		September 30,		September 30,
(in thousands, except sales price data)		2005	2004	2005	2004
Oil and Gas Operations
Operating revenues from continuing operations
Natural gas		$   85,087	$    69,745	$ 247,087	$ 200,363
Oil		28,879	24,553	83,683	70,262
Natural gas liquids		10,721	9,065	28,519	22,220
Other		1,573	818	4,278	2,693
Total		$  126,260	$  104,181	$ 363,567	$ 295,538
Production volumes from continuing operations
Natural gas (MMcf)		16,013	14,632	45,871	42,063
Oil (MBbl)		813	854	2,480	2,558
Natural gas liquids (MMgal)		18.1	18.2	52.5	50.3
Production volumes from continuing operations (MMcfe)		23,480	22,349	68,247	64,599
Total production volumes (MMcfe)		23,478	22,374	68,303	64,684
Average sales price including effects of derivative instruments
Natural gas (Mcf)		$       5.31	$        4.77	$       5.39	$        4.76
Oil (barrel)		$     35.51	$      28.76	$    33.75	$      27.47
Natural gas liquids (gallon)		$      0.59	$       0.50	$ 0.54	$ 0.44
Average sales price excluding effects of derivative contracts marked-to-market and ineffectiveness related to contracts that have not closed
Natural gas (Mcf)		$       6.45	$        4.74	$       5.98	$        4.81
Oil (barrel)		$     36.98	$      30.75	$    34.59	$      28.94
Natural gas liquids (gallon)		$      0.59	$       0.50	$ 0.54	$ 0.44
Average sales price excluding effects of derivative instruments
Natural gas (Mcf)		$       7.78	$        5.44	$      6.72	$        5.45
Oil (barrel)		$     58.64	$      40.82	$    50.51	$      36.39
Natural gas liquids (gallon)		$     0.83	$       0.63	$    0.71	$       0.55
Other data from continuing operations
Lease operating expense (LOE)
LOE and other		$   27,396	$    22,068	$  75,511	$    58,298
Production taxes		$   13,477	$     9,565	$  35,550	$   26,255
Total		$    40,873	$    31,633	$   111,061	$  84,553
Depreciation, depletion and amortization		$    23,547	$ 20,864	$   67,017	$    58,965
Capital expenditures		$    44,209	$  288,585	$ 132,718	$ 359,993
Exploration expenditures		$      74	$   1,807	$       568	$   1,907
Operating income		$   52,368	$    42,584	$ 156,713	$  128,321
Natural Gas Distribution
Operating revenues
Residential		$    33,795	$   33,860	$ 276,728	$ 267,164
Commercial and industrial		21,732	18,516	116,612	107,692
Transportation		9,378	8,838	32,652	29,316
Other		(484)	948	3,754	5,936
Total		$ 64,421	$   62,162	$ 429,746	$  410,108
Gas delivery volumes (MMcf)
Residential		1,810	1,874	18,992	20,743
Commercial and industrial		1,791	1,570	9,497	9,845
Transportation		11,951	12,790	37,634	40,571
Total		15,552	16,234	66,123	71,159
Other data
Depreciation and amortization		$   10,668	$     9,985	$   31,724	$   29,453
Capital expenditures		$   17,863	$   11,869	$   53,562	$   42,090
Operating income (loss)	$   (11,025)		$  (10,130)	$   61,009	$   56,459

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," to hedge its exposure to price fluctuations on 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 am ounts. Notwithstanding these agreements, the Company is at risk for economic loss based upon the creditworthiness of its counterparties. In some contracts, the amount of credit allowed before Energen Resources and Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2007.

See Note 4 to the Unaudited Condensed Financial Statements for details related to the Company's hedging activities.

The Company's interest rate exposure as of September 30, 2005, was minimal since approximately 85 percent of long-term debt obligations were at fixed rates.

ITEM 4. CONTROLS AND PROCEDURES
(a)	Our chief executive officer and chief financial officer have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective at a reasonable assurance level.
(b)	Our chief executive officer and chief financial officer have concluded that during the period covered by this report there were no changes in our internal controls that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS*
Period	Total Number of Shares Purchased**	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Progams***
July 1, 2005 through July 30, 2005	436	$ 35.98	-	-
August 1, 2005 through August 31, 2005	436	$ 34.93	-	-
September 1, 2005 through September 30, 2005	24,970	$ 39.01	-	2,150,700
Total	25,842	$ 38.89	-	2,150,700
* Share and per share data have been restated to reflect a 2-for-1 stock split payable June 1, 2005 (see Note 15 to theUnaudited Condensed Financial Statements).
** Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans.
*** By resolution adopted May 24, 1994, and supplemented by a resolution adopted April 26, 2000, the Board of Directors authorized the Company to repurchase up to 3,564,400 shares of the Company's common stock. The resolutions do not have an expiration date.
ITEM 6. EXHIBITS
31(a) - Section 302 Certificate required by Rule 13a-14(a) or Rule 15d-14(a) 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
SIGNATURES Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	ENERGEN CORPORATION
	ALABAMA GAS CORPORATION
November 8, 2005	By   /s/ Wm. Michael Warren, Jr.
	Wm. Michael Warren, Jr.
	Chairman, President and Chief Executive
	Officer of Energen Corporation, Chairman and Chief Executive Officer of
	Alabama Gas Corporation
November 8, 2005	By   /s/ G. C. Ketcham
	G. C. Ketcham
	Executive Vice President, Chief
	Financial Officer and Treasurer of
	Energen Corporation and Alabama Gas
	Corporation
November 8, 2005	By   /s/ Grace B. Carr
	Grace B. Carr
	Vice President and Controller of Energen
	Corporation
November 8, 2005	By   /s/ Paula H. Rushing
	Paula H. Rushing
	Vice President-Finance of Alabama Gas
	Corporation