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 QUARTER ENDED SEPTEMBER 30, 2003

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 X NO ____

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). YES X NO ____

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of November 11, 2003

Energen Corporation	$0.01 par value	36,143,645 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, 2003
TABLE OF CONTENTS
		Page
PART I: FINANCIAL INFORMATION
Item 1.	Financial Statements
	(a) Consolidated Condensed Statements of Income of Energen Corporation	3
	(b) Consolidated Condensed Balance Sheets of Energen Corporation	4
	(c) Consolidated Condensed Statements of Cash Flows of Energen Corporation	6
	(d) Condensed Statements of Income of Alabama Gas Corporation	7
	(e) Condensed Balance Sheets of Alabama Gas Corporation	8
	(f) Condensed Statements of Cash Flows of Alabama Gas Corporation	10
	(g) Notes to Unaudited Condensed Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21
	Selected Business Segment Data of Energen Corporation	27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28
Item 4.	Controls and Procedures	29
	PART II: OTHER INFORMATION
Item 6.	Exhibits and Reports on Form 8-K	30
SIGNATURES		31

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)	2003	2002	2003	2002
Operating Revenues
Oil and gas operations	$   87,994	$   64,619	$  266,296	$  171,643
Natural gas distribution	58,147	50,225	373,534	322,458
Total operating revenues	146,141	114,844	639,830	494,101
Operating Expenses
Cost of gas	24,966	17,897	179,045	144,038
Operations and maintenance	50,227	47,772	149,005	137,686
Depreciation, depletion and amortization	29,203	26,773	87,473	76,501
Taxes, other than income taxes	12,389	9,265	47,824	36,326
Total operating expenses	116,785	101,707	463,347	394,551
Operating Income	29,356	13,137	176,483	99,550
Other Income (Expense)
Interest expense	(10,153)	(10,987)	(31,709)	(32,828)
Accretion expense	(459)	(480)	(1,419)	(1,331)
Other income	2,289	3,885	7,408	10,583
Other expense	(2,866)	(4,020)	(8,218)	(10,614)
Total other expense	(11,189)	(11,602)	(33,938)	(34,190)
Income From Continuing Operations Before Income Taxes and Cumulative Effect of Change in Accounting Principle	18,167	1,535	142,545	65,360
Income tax expense	6,710	1,438	53,305	13,817
Income From Continuing Operations Before Cumulative Effect of Change in Accounting Principle	11,457	97	89,240	51,543
Discontinued Operations, net of taxes
Income (loss) from discontinued operations	145	63	966	(43)
Gain (loss) on disposal	294	(33)	(382)	273
Income From Discontinued Operations	439	30	584	230
Cumulative Effect of Change in Accounting Principle, net of taxes	-	-	-	(2,220)
Net Income	$    11,896	$      127	$    89,824	$  49,553
Diluted Earnings Per Average Common Share
Continuing operations	$      0.32	$       -	$      2.51	$   1.54
Discontinued operations	0.01	-	0.02	0.01
Cumulative effect of change in accounting principle	-	-	-	(0.07)
Net Income	$        0.33	$     -	$        2.53	$   1.48
Basic Earnings Per Average Common Share
Continuing operations	$      0.32	$       -	$      2.53	$   1.55
Discontinued operations	0.01	-	0.02	0.01
Cumulative effect of change in accounting principle	-	-	-	(0.07)
Net Income	$     0.33	$     -	$     2.55	$  1.49
Dividends Per Common Share	$      0.185	$     0.18	$    0.545	$   0.53
Diluted Average Common Shares Outstanding	36,261	34,731	35,561	33,543
Basic Average Common Shares Outstanding	35,869	34,425	35,208	33,245

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

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	September 30, 2003	December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$       4,741	$       4,804
Accounts receivable, net of allowance for doubtful     accounts of $9,720 at September 30, 2003, and     $8,874 at December 31, 2002	85,191	139,356
Inventories, at average cost
Storage gas inventory	57,849	23,668
Materials and supplies	9,125	8,335
Liquified natural gas in storage	3,256	3,671
Deferred income taxes	33,605	33,941
Prepaid pension	19,192	-
Regulatory asset	10,536	-
Prepayments and other	5,427	20,367
	228,922
Total current assets		234,142
Property, Plant and Equipment
Oil and gas properties, successful efforts method	1,148,057	1,103,472
Less accumulated depreciation, depletion and amortization	291,558	269,616
Oil and gas properties, net	856,499	833,856
Utility plant	867,769	825,421
Less accumulated depreciation	436,628	408,165
Utility plant, net	431,141	417,256
Other property, net	5,084	5,691
Total property, plant and equipment, net	1,292,724	1,256,803
Other Assets
Deferred income taxes	-	16,333
Regulatory asset	18,313	14,744
Deferred charges and other	28,029	26,239
Total other assets	46,342	57,316
TOTAL ASSETS	$   1,567,988	$   1,548,261

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

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands, except share data)	September 30, 2003	December 31, 2002
CAPITAL AND LIABILITIES
Current Liabilities
Long-term debt due within one year	$      20,000	$      23,000
Notes payable to banks	39,000	113,000
Accounts payable	92,797	103,964
Accrued taxes	37,289	27,936
Customers' deposits	16,138	17,404
Amounts due customers	4,912	8,458
Accrued wages and benefits	23,982	23,652
Regulatory liability	16,399	41,184
Other	37,266	34,710
Total current liabilities	287,783	393,308
Deferred Credits and Other Liabilities
Asset retirement obligation	24,030	27,235
Minimum pension liability	35,786	25,825
Regulatory liability	1,955	1,468
Deferred income taxes	19,634	-
Other	9,831	4,661
Total deferred credits and other liabilities	91,236	59,189
Commitments and Contingencies
Capitalization
Preferred stock, cumulative $0.01 par value, 5,000,000     shares authorized	-	-
Common shareholders' equity
Common stock, $0.01 par value; 75,000,000 shares authorized, 36,033,711 shares outstanding at September 30, 2003, and 34,745,477 shares outstanding at December 31, 2002	360	347
Premium on capital stock	361,461	320,060
Capital surplus	2,802	2,802
Retained earnings	345,859	275,266
Accumulated other comprehensive loss, net of tax	(22,966)	(14,811)
Deferred compensation on restricted stock	(1,579)	(770)
Deferred compensation plan	14,150	10,348
Treasury stock, at cost (391,089 shares at September 30, 2003,     and 358,228 shares at December 31, 2002)	(14,150)	(10,432)
Total common shareholders' equity	685,937	582,810
Long-term debt	503,032	512,954
Total capitalization	1,188,969	1,095,764
TOTAL CAPITAL AND LIABILITIES	$   1,567,988	$   1,548,261

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

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Nine months ended September 30, (in thousands)	2003	2002
Operating Activities
Net income	$     89,824	$     49,553
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization	88,400	83,180
Deferred income taxes	40,804	8,397
Deferred investment tax credits	(336)	(336)
Change in derivative fair value	748	(7,807)
Gain on sale of assets	(10,059)	(3,373)
Loss on properties held-for-sale	10,404	-
Cumulative effect of change in accounting principle, net of taxes	-	2,220
Net change in:
Accounts receivable	41,558	23,066
Inventories	(34,556)	12,623
Accounts payable	(25,146)	(7,467)
Amounts due customers	1,026	(1,613)
Other current assets and liabilities	(16,661)	(591)
Other, net	3,090	260
Net cash provided by operating activities	189,096	158,112
Investing Activities
Additions to property, plant and equipment	(153,960)	(108,118)
Acquisition	-	(117,043)
Proceeds from sale of assets	29,092	14,335
Other, net	636	(600)
Net cash used in investing activities	(124,232)	(211,426)
Financing Activities
Payment of dividends on common stock	(19,236)	(17,690)
Issuance of common stock	41,648	7,556
Purchase of treasury stock	(339)	-
Reduction of long-term debt	(13,000)	(21,204)
Net change in short-term debt	(74,000)	82,928
Net cash provided by (used in) financing activities	(64,927)	51,590
Net change in cash and cash equivalents	(63)	(1,724)
Cash and cash equivalents at beginning of period	4,804	6,482
Cash and Cash Equivalents at End of Period	$      4,741	$       4,758

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)	2003	2002	2003	2002

Operating Revenues	$ 58,147	$ 50,225	$ 373,534	$ 322,458
Operating Expenses
Cost of gas	25,534	18,307	180,828	145,231
Operations and maintenance	27,657	28,053	84,208	80,641
Depreciation	9,385	8,492	27,532	25,035
Income taxes
Current	(10,164)	(9,735)	9,712	7,666
Deferred, net	5,331	4,905	7,174	6,795
Deferred investment tax credits, net	(112)	(112)	(336)	(336)
Taxes, other than income taxes	5,146	4,280	26,353	22,926
Total operating expenses	62,777	54,190	335,471	287,958
Operating Income (Loss)	(4,630)	(3,965)	38,063	34,500
Other Income (Expense)
Allowance for funds used during construction	80	312	573	837
Other income	897	1,135	3,090	3,832
Other expense	(1,032)	(1,623)	(3,642)	(4,493)
Total other income (expense)	(55)	(176)	21	176
Interest Charges
Interest on long-term debt	3,222	3,265	9,697	9,917
Other interest expense (income)	(126)	294	586	953
Total interest charges	3,096	3,559	10,283	10,870
Net Income (Loss)	$ (7,781)	$ (7,700)	$ 27,801	$ 23,806

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

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	September 30, 2003	December 31, 2002
ASSETS
Property, Plant and Equipment
Utility plant	$   867,769	$   825,421
Less accumulated depreciation	436,628	408,165
Utility plant, net	431,141	417,256
Other property, net	332	842
Current Assets
Cash and cash equivalents	3,873	2,818
Accounts receivable
Gas	55,296	108,630
Merchandise	1,049	1,748
Other	3,108	656
Allowance for doubtful accounts	(9,100)	(8,200)
Inventories, at average cost
Storage gas inventory	57,849	23,668
Materials and supplies	6,232	5,049
Liquified natural gas in storage	3,256	3,671
Deferred income taxes	18,550	20,093
Regulatory asset	10,536	-
Prepaid pension	15,658	-
Prepayments and other	2,867	18,314
Total current assets	169,174	176,447
Other Assets
Regulatory asset	18,313	14,744
Deferred charges and other	10,642	11,290
Total other assets	28,955	26,034
TOTAL ASSETS	$   629,602	$   620,579

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, 2003	December 31, 2002
CAPITAL AND LIABILITIES
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares     authorized, issuable in series-$4.70 Series	$              -	$           -
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares        authorized, 1,972,052 shares outstanding at        September 30, 2003, and December 31, 2002	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	210,654	182,852
Total common shareholder's equity	245,158	217,356
Long-term debt	169,533	169,533
Total capitalization	414,691	386,889
Current Liabilities
Long-term debt due within one year	10,000	15,000
Notes payable to banks	-	13,000
Accounts payable	50,535	55,720
Amounts due to affiliates	20,225	1,432
Accrued taxes	28,256	24,044
Customers' deposits	16,138	17,404
Amounts due customers	4,912	8,458
Accrued wages and benefits	5,532	5,710
Regulatory liability	16,399	41,184
Other	10,626	8,947
Total current liabilities	162,623	190,899
Deferred Credits and Other Liabilities
Deferred income taxes	26,630	20,747
Minimum pension liability	21,635	18,661
Accumulated deferred investment tax credits	420	756
Regulatory liability	1,955	1,468
Customer advances for construction and other	1,648	1,159
Total deferred credits and other liabilities	52,288	42,791
Commitments and Contingencies
TOTAL CAPITAL AND LIABILITIES	$   629,602	$   620,579

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)	2003	2002
Operating Activities
Net income	$     27,801	$     23,806
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization	27,532	25,035
Deferred income taxes, net	7,174	6,795
Deferred investment tax credits	(336)	(336)
Net change in:
Accounts receivable	39,873	29,410
Inventories	(34,950)	12,887
Accounts payable	(14,900)	15,997
Amounts due customers	1,026	(1,613)
Other current assets and liabilities	(12,422)	(20,924)
Other, net	123	(764)
Net cash provided by operating activities	40,921	90,293
Investing Activities
Additions to property, plant and equipment	(40,966)	(49,803)
Other, net	307	424
Net cash used in investing activities	(40,659)	(49,379)
Financing Activities
Dividends	-	(11,159)
Net advances from (to) affiliates	18,793	(6,182)
Reduction of long-term debt	(5,000)	(5,467)
Net change in short-term debt	(13,000)	(19,000)
Net cash used in financing activities	793	(41,808)
Net change in cash and cash equivalents	1,055	(894)
Cash and cash equivalents at beginning of period	2,818	3,372
Cash and Cash Equivalents at End of Period	$        3,873	$      2,478

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 financial statements and notes should be read in conjunction with the financial statements and notes thereto for the year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000, included in the 2002 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. On December 5, 2001, the Board of Directors of the Company approved a change in the Company's fiscal year end from September 30 to December 31, effective January 1, 2002. A transition report was filed on Form 10-Q for the period October 1, 2001, to December 31, 2001. 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. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company's natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year. The quarterly information reflects the adoption in 2002 of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." Upon adoption of SFAS No. 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as the cost of the asset as of January 1, 2002. Upon initial application of the Statement, a cumulative effect of a change in accounting principle of $2.2 million after-tax was required in order to recognize a liability for any existing asset retirement obligations. The Company adopted SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets," on January 1, 2002. 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 of operations 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. 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 four years; therefore, the cost related to stock-based employee compensation included in the determination of net income for the three months and nine months ended September 30, 2003 and 2002, is less than 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 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)	2003	2002	2003	2002
Net income
As reported	$ 11,896	$ 127	$ 89,824	$ 49,553
Stock-based compensation expense included in reported net income, net of tax	857	296	2,216	1,441
Stock-based compensation expense determined under fair value based method, net of tax	(960)	(486)	(2,336)	(1,481)
Pro forma	$ 11,793	$ (63)	$ 89,704	$ 49,513
Diluted earnings per average common share
As reported	$ 0.33	$ -	$ 2.53	$      1.48
Pro forma	$ 0.33	$ -	$ 2.52	$      1.48
Basic earnings per average common share
As reported	$ 0.33	$ -	$ 2.55	$      1.49
Pro forma	$ 0.33	$ -	$ 2.55	$      1.49

3. REGULATORY

All of Alagasco's utility operations are conducted in the state of Alabama. Alagasco is subject to regulation by the APSC which established the 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 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's allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the equity returns of all major energy utilities operating under a similar methodology. Under RSE as extended, 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 13.15 percent to 13.65 percent. 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, 2003, Alagasco had a $3 million reduction in revenues to bring the return on average equity within the allowed range of return. 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 slightly above the index range for the rate year ended September 30, 2003; as a result, the utility had a $102,000 reduction to revenues under the provisions of RSE. A $12.4 million and $16.3 million annual increase in revenues became effective December 1, 2002 and 2001, respectively, under RSE.

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 to residential, small commercial and small industrial customers. 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.

The APSC approved an Enhanced Stability Reserve (ESR) beginning rate year 1998, with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco's return on average equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR of no more than $40,000 monthly until the maximum funding level is achieved. At September 30, 2003, and December 31, 2002, ESR balances of $3.4 million and $3 million, respectively, were included in regulatory liability on the consolidated financial statements.

At September 30, 2003, and December 31, 2002, Alagasco had a $21.6 million and an $18.7 million, respectively, accrued obligation related to its salaried and union pension plans. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," Alagasco recorded a regulatory asset of $18.3 million and $14.7 million at September 30, 2003, and December 31, 2002, respectively, for the portion of the accrued obligation to be recovered through rates in future periods.

At September 30, 2003, Alagasco revised its balance sheet presentation to reflect the margin on service delivered to cycle customers but not yet billed in current assets as accounts receivable with a corresponding regulatory liability and has reclassified deferred gas costs as accounts receivable. As a result, current assets and regulatory liability increased $4.8 million and $17.4 million at September 30, 2003, and December 31, 2002, respectively. The underlying financial statements related to the annual establishment of Alagasco's rates and any subsequent quarterly adjustments continue to reflect revenues in results of operations on an as-billed basis as required by the APSC.

4. DERIVATIVE COMMODITY INSTRUMENTS

The Company applies SFAS No. 133 (as amended), "Accounting for Derivative Instruments and Hedging Activities," 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 Company is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, 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 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 earnings in the period of change.

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 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 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 Energen Resources or Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade status to have available counterparty credit.

Energen Resources had certain agreements with Enron North America Corp. (Enron) as the counterparty as of October 1, 2001. As prescribed by SFAS No. 133, the value of the outstanding Enron contracts which qualified for cash flow hedge accounting treatment was reflected on the balance sheet as an asset and the effective portion of the derivative was reported as OCI. These outstanding contracts ceased to qualify as cash flow hedges during October 2001 as a result of Enron's credit issues. The Company recorded an expense to O&M for the write-down to fair value of the asset related to the effected derivative contracts. The deferred revenues related to the non-performing hedges were recorded in accumulated other comprehensive income until such time as they were reclassified to earnings as originally forecasted to occur. As a result, Energen's net income in the three-month transition period ended December 31, 2001, reflected a one-time, non-cash expense of $5.5 million, net of tax. Energen's net income reflected a non-cash benefit of $1.6 million, net of tax, for the three-month period ended September 30, 2002, and a $5.6 million, net of tax, non-cash benefit for the nine-month period ended September 30, 2002. Net income in the year ended December 31, 2002, reflected a total non-cash benefit of $5.7 million, net of tax, related to the Enron hedge position.

As of September 30, 2003, $11.2 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to earnings during the next 12-month period. The actual amounts 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, the Company recorded a $106,000 loss for the three months ended September 30, 2003, and a $1.2 million after-tax loss in the year-to-date period. Also, Energen Resources recorded an after-tax gain of $191,000 for the quarter and a $369,000 after-tax loss in the year-to-date period on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of September 30, 2003, the Company had 0.82 billion cubic feet (Bcf) of gas hedges, 0.02 Bcf of gas basis hedges, 6,000 barrels (Bbl) of oil hedges and 6,000 Bbl of oil basis hedges which expire by year-end that did not meet the definition of a cash flow hedge but are considered by the Company to be viable economic hedges. As of September 30, 2003, and December 31, 2002, the Company had assets of $9 million and $6.7 million, respectively, included in current and noncurrent deferred income taxes on the consolidated balance sheets related to OCI.

Energen Resources has entered into the following transactions for the remainder of 2003 and subsequent years:

Production Period	Total Hedged Volume	Average Contract Price	Description
Natural Gas
2003	8.4 Bcf	$4.12 Mcf	NYMEX Swaps
	1.1 Bcf	$4.06 Mcf	Basin Specific Swaps
	1.2 Bcf	$3.72 - $4.70 Mcf	Basin Specific Collars
2004	8.9 Bcf	$4.13 Mcf	NYMEX Swaps
	18.7 Bcf	$4.07 Mcf	Basin Specific Swaps
	2.4 Bcf	$4.05 - $4.44 Mcf	NYMEX Collars
2005	1.2 Bcf	$3.75 Mcf	NYMEX Swaps
	6.0 Bcf	$3.96 Mcf	Basin Specific Swaps
Natural Gas Basis Differential
2003	4.3 Bcf	**	Basis Swaps
Oil
2003	561 MBbl	$25.92 Bbl	NYMEX Swaps
2004	1,083 MBbl	$27.29 Bbl	NYMEX Swaps
	* 225 MBbl	$28.59 Bbl	NYMEX Swaps
Oil Basis Differential
2003	531 MBbl	**	Basis Swaps
2004	180 MBbl	**	Basis Swaps
Natural Gas Liquids
2003	9.5 MMGal	$0.42 Gal	Liquids Swaps
2004	37.2 MMGal	$0.41 Gal	Liquids Swaps
* Contracts entered into subsequent to September 30, 2003.
** Average contract prices 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 Resources has hedged exposures to the variability of cash flows is through December 31, 2005.

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 at fair value as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with its APSC-approved tariff. In accordance with SFAS No. 71, Alagasco had recorded a current regulatory asset of $10.5 million and a noncurrent regulatory liability of $0.8 million representing the fair value of derivatives as of September 30, 2003. As of December 31, 2002, Alagasco recorded a current regulatory liability of $16.8 million 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, 2003				September 30, 2002
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount
Basic EPS	$   11,896		35,869	$   0.33	$  127		34,425	$   -
Effect of Dilutive Securities
Long-range performance shares			139				148
Stock options			241				155
Restricted stock			12				3
Diluted EPS	$   11,896		36,261	$   0.33	$   127		34,731	$   -

		Nine months ended				Nine months ended
(in thousands, except per share amounts)		September 30, 2003				September 30, 2002
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount
Basic EPS	$   89,824		35,208	$   2.55	$  49,553		33,245	$   1.49
Effect of Dilutive Securities
Long-range performance shares			132				147
Stock options			212				149
Restricted stock			9				2
Diluted EPS	$   89,824		35,561	$   2.53	$  49,553		33,543	$   1.48

For the three months and the nine months ended September 30, 2003, 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)	2003	2002	2003	2002
Operating revenues from continuing operations
Oil and gas operations	$ 88,562	$ 65,029	$ 268,079	$ 172,836
Natural gas distribution	58,147	50,225	373,534	322,458
Eliminations and other	(568)	(410)	(1,783)	(1,193)
Total	$ 146,141	$ 114,844	$ 639,830	$ 494,101
Operating income (loss) from continuing operations
Oil and gas operations	$ 39,417	$ 22,464	$ 123,068	$ 52,273
Natural gas distribution	(9,575)	(8,907)	54,613	48,625
Eliminations and corporate expenses	(486)	(420)	(1,198)	(1,348)
Total	$ 29,356	$ 13,137	$ 176,483	$ 99,550
Other income (expense)
Oil and gas operations	$ (7,501)	$ (7,979)	$ (22,811)	$ (23,563)
Natural gas distribution	(3,151)	(3,735)	(10,262)	(10,694)
Eliminations and other	(537)	112	(865)	67
Total	$ (11,189)	$ (11,602)	$ (33,938)	$ (34,190)
Income from continuing operations before income taxes and cumulative effect of change in accounting principle	$ 18,167	$ 1,535	$ 142,545	$ 65,360

(in thousands)	September 30, 2003	December 31, 2002
Identifiable assets
Oil and gas operations	$    917,529	$     926,839
Natural gas distribution	628,785	620,579
Eliminations and other	20,857	843
Total	$ 1,567,171	$ 1,548,261

7. COMPREHENSIVE INCOME (LOSS) Comprehensive income (loss) consisted of the following:
	Three months ended	Three months ended
(in thousands)	September 30, 2003	September 30, 2002
Net Income	$    11,896	$     127
Other comprehensive income (loss)
Current period change in fair value of derivative instruments,       net of tax of $7.8 million and ($2.0) million	12,190	(3,168)
Reclassification adjustment, net of tax of $4.3 million and       ($1.3) million	6,659	(2,069)
Minimum pension liability, net of tax of ($2.4) million and ($0.9) million	(4,540)	(1,654)
Comprehensive Income (Loss)	$   26,205	$    (6,764)

	Nine months ended	Nine months ended
(in thousands)	September 30, 2003	September 30, 2002
Net Income	$    89,824	$    49,553
Other comprehensive income (loss)
Current period change in fair value of derivative instruments,       net of tax of ($21.1) million and ($3.2) million	(32,972)	(5,005)
Reclassification adjustment, net of tax of $18.8 million and       ($3.1) million	29,357	(4,845)
Minimum pension liability, net of tax of ($2.4) million and ($0.9) million	(4,540)	(1,654)
Comprehensive Income	$    81,669	$    38,049

Accumulated other comprehensive income (loss) consisted of the following:
(in thousands)			September 30, 2003			December 31, 2002
Unrealized loss on hedges, net of tax of ($9) million and ($6.7) million			$    (14,086)			$    (10,471)
Minimum pension liability, net of tax of ($4.8) million and ($2.3) million			(8,880)			(4,340)
Accumulated Other Comprehensive Loss			$    (22,966)			$    (14,811)
8. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS On January 1, 2002, the Company adopted 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 in 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. All assets held-for-sale must be reported at the lower of the carrying amount or fair value. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. During the nine months ended September 30, 2003, Energen Resources recorded a pre-tax writedown to fair value based upon expected market value of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region. These properties were sold in August 2003, for a pre-tax gain of $0.4 million. The pre-tax gain on disposals for the three months ended September 30, 2003, was $0.5 million and $9.8 million for the nine months ended September 30, 2003, largely due to sales of properties located in the San Juan Basin. 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)		2003		2002	2003		2002
Oil and gas revenues		$ 63		$ 2,192	$ 3,577		$ 7,425
Pretax income (loss) from discontinued operations		$ 238		$ 108	$ 1,583		$ (68)
Income tax expense (benefit)		93		45	617		(25)
Income (Loss) From Discontinued Operations		145		63	966		(43)
Impairment charge on held-for-sale property		-		-	(10,404)		(2,815)
Gain (loss) on disposal		481		(53)	9,778		3,263
Income tax expense (benefit)		187		(20)	(244)		175
Gain (Loss) on Disposal		294		(33)	(382)		273
Total Income From Discontinued Operations		$ 439		$ 30	$ 584		$ 230
Diluted Earnings Per Average Common Share
Income from Discontinued Operations		$ -		$ -	$ 0.03		$ -
Gain (Loss) on Disposal		0.01		-	(0.01)		0.01
Total Income from Discontinued Operations		$ 0.01		$ -	$ 0.02		$ 0.01
Basic Earnings Per Average Common Share
Income from Discontinued Operations		$ -		$ -	$ 0.03		$ -
Gain (Loss) on Disposal		0.01		-	(0.01)		0.01
Total Income from Discontinued Operations		$ 0.01		$ -	$ 0.02		$ 0.01
9. ACQUISITION OF OIL AND GAS PROPERTIES On April 8, 2002, Energen Resources completed its purchase of oil and gas properties located in the Permian Basin in west Texas from First Permian, L.L.C. (First Permian), for approximately $120 million cash and 3,043,479 shares of the Company's common stock. The common stock was valued at $23.95 per share, the average stock price at the time Energen signed the related Purchase and Sale Agreement. The total acquisition approximated $184 million. Summarized below are the consolidated results of operations for the nine months ended September 30, 2002, 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 nine months ended September 30, 2002, and on the data provided by the seller, after giving effect to the issuance of 3,043,479 million shares of common stock. 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.
	Nine months ended
(in thousands, except per share data)	September 30, 2002
Operating revenues		$   500,706
Income from continuing operations before cumulative effect of change in accounting principle		$  51,543
Net income		$  50,686
Diluted earnings per average common share		$        1.54
Basic earnings per average common share		$        1.55

10. EQUITY AND DEBT OFFERINGS

In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. The sale of shares began May 9, 2003, and concluded on July 16, 2003, generating net proceeds of $32.2 million. In October 2003, Energen issued $50 million of long-term debt due October 1, 2013. The 5% coupon notes were priced at 99.557 percent to yield 5.057 percent. These proceeds will be 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.

11. COMMITMENTS AND CONTINGENCIES

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.

Various 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 and results of operationsand 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. 

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

12. REGULATORY ASSETS AND LIABILITIES The following table details regulatory assets and liabilities on the consolidated balance sheets:
Energen Corporation
(in thousands)	September 30, 2003		December 31, 2002
	Current	Noncurrent	Current	Noncurrent
Regulatory assets:
Pension asset	$       -	$    18,313	$       -	$     14,744
Risk management activities	10,536	-	-	-
Total regulatory assets	$   10,536	$    18,313	$       -	$    14,744
Regulatory liabilities:
Enhanced stability reserve	$    3,439	$     -	$    2,963	$       -
Gas supply adjustment	5,378	-	3,845	-
Risk management activities	-	817	16,750	-
RSE adjustment	2,819	-	256	-
Unbilled service margin	4,763	-	17,370	-
Other	-	1,138	-	1,468
Total regulatory liabilities	$     16,399	$      1,955	$     41,184	$       1,468

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

The FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosures Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," (FIN 45) in November 2002. FIN 45 clarifies the requirements of SFAS No. 5, "Accounting for Contingencies," related to a guarantor's accounting for, and disclosures of, the issuance of certain types of guarantees. Management has completed a review of potential contingencies and noted the following guarantee disclosures: 1) Alagasco has an agreement with a financial institution whereby it can sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $15 million. Alagasco's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables. The Company adopted the provisions for recognition and measurement for all guarantees issued or modified after December 31, 2002, on a prospective basis. The fair value of guarantees issued after December 31, 2002, is not significant to the Company. 2) Alagasco purchases gas as agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to 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 losses. At September 30, 2003, the gas guaranteed had an aggregate purchase price of $17.5 million and a market value of $16 million. The maximum term over which Alagasco has guarantees outstanding is through December 2004.

SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," were issued by the FASB in June 2001 and became effective on July 1, 2001, and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method and SFAS No. 142 establishes new guidelines in accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain intangible assets that have indefinite useful lives are not amortized, but rather are reviewed annually for impairment. The appropriate application of SFAS No. 141 and SFAS No. 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves is currently being considered. One interpretation relative to these standards is that oil and gas mineral rights for both undeveloped and developed leaseholds could be classified separately from oil and gas properties as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. In addition, the disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements. The Company anticipates that this interpretation of SFAS No. 141 and SFAS No. 142 would only affect balance sheet classifications of oil and gas leaseholds. Results of operations and cash flows are not anticipated to be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Company will continue to evaluate the impact of the application of these standards as further guidance is provided.

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

Energen's net income totaled $11.9 million ($0.33 per diluted share) for the three months ended September 30, 2003, and compared favorably to net income of $0.1 million ($0.00 per diluted share) recorded in the same period last year. In the third quarter of 2003, Energen's income from continuing operations totaled $11.5 million ($0.32 per diluted share) and compared with income from continuing operations of $0.1 million ($0.00 per diluted share) in the same period a year ago. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended September 30, 2003, of $20.3 million as compared with $7.9 million in the previous period. Energen Resources generated net income from continuing operations of $19.9 million in the current quarter as compared with $7.9 million in the same quarter last year primarily as a result of significantly increased commodity prices for oil, natural gas and natural gas liquids as well as the impact of higher gas production volumes. Prior period income from continuing operations included a non-cash benefit of $1.6 million after-tax ($0.04 per diluted share) associated with its previous hedge position with Enron North America Corp. (Enron) and the recognition of $1.2 million of income tax expense relating to the interim reporting of non-conventional fuels tax credits. Energen's natural gas utility, Alagasco, reported net loss of $7.8 million in the third quarter of 2003 as compared to net loss of $7.7 million in the same period last year. 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 2003 year-to-date, Energen's net income totaled $89.8 million ($2.53 per diluted share) and compared favorably to net income of $49.6 million ($1.48 per diluted share) for the same period in the prior year. For the nine months ended September 30, 2003, Energen's income from continuing operations before the cumulative effect of a change in accounting principle totaled $89.2 million ($2.51 per diluted share) and compared with $51.5 million ($1.54 per diluted share) in the same period a year ago. Energen Resources had net income for the nine months ended September 30, 2003, of $62.7 million as compared with $26.1 million in the previous period. Net income in the prior year-to-date included a one-time charge of $2.2 million after-tax ($0.07 per diluted share), reflecting the cumulative effect on prior years of the adoption of Statement of Financial Accounting Standard (SFAS) No. 143, "Accounting for Asset Retirement Obligations." Energen Resources generated income from continuing operations before the cumulative effect of a change in accounting principle of $62.1 million in the current year-to-date as compared with $28.1 million in the same period last year primarily as a result of higher commodity prices along with the impact of increased oil and gas production volumes. Prior period income from continuing operations before the cumulative effect of a change in accounting principle included a non-cash benefit of $5.6 million after-tax ($0.17 per diluted share) associated with its previous hedge position with Enron and the recognition of $10.4 million in non-conventional fuels tax credits. Alagasco's earnings of $27.8 million in the current year-to-date increased from net income of $23.8 million in the same period in the previous year. This increase in earnings partially reflected the utility's ability to earn on a higher level of equity representing investment in utility plant. It also reflected the impact of timing differences between the rate year and calendar year as it relates to revenue recovery under the utility's rate-setting mechanism.

Oil and Gas Operations

Revenues from oil and gas operations rose 36.2 percent to $88 million for the three months ended September 30, 2003, largely as a result of significantly increased commodity prices and increased gas production volumes. For the year-to-date, revenues from oil and gas operations increased 55.1 percent to $266.3 million primarily due to increased gas, oil and liquids prices and increased production volumes. In the current quarter, average gas prices, including the prior period non-cash benefit from the former Enron hedges, increased 31.8 percent to $4.27 per thousand cubic feet (Mcf), while average oil prices rose 6.4 percent to $25.30 per barrel and natural gas liquids prices increased 24.6 percent to an average price of $15.82 per barrel. For the year-to-date, including the prior period non-cash benefit from the former Enron hedges, average gas prices increased 41.9 percent to $4.30 per Mcf, average oil prices increased 9.7 percent to $25.64 per barrel and natural gas liquids prices increased 34.7 percent to an average price of $16.03 per barrel.

Natural gas production from continuing operations in the third quarter increased 19.5 percent to 14 billion cubic feet (Bcf), while oil volumes remained stable at 838 thousand barrels (MBbl). Natural gas liquids production declined 13.2 percent to 395 MBbl. The increase in natural gas production in the current quarter largely was due to a new Permian Basin gas project, acquisitions in the San Juan Basin and the successful coalbed methane down-spacing program. For the year-to-date, natural gas production rose 21.8 percent to 41.5 Bcf, oil volumes increased 16.4 percent to 2,539 MBbl and natural gas liquids production declined 5.4 percent to 1,179 MBbl. The increase in natural gas and oil production largely was due to the same reasons that influenced the quarter results as well as a prior year acquisition of oil properties in the Permian Basin. Natural gas comprised approximately 65 percent of Energen Resources' production for the current quarter and the year-to-date.

Energen Resources 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. Such instruments 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 Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade status to have available counterparty credit. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions.

Energen Resources has entered into the following transactions for the remainder of 2003 and subsequent years:

Production Period	Total Hedged Volume	Average Contract Price	Description
Natural Gas
2003	8.4 Bcf	$4.12 Mcf	NYMEX Swaps
	1.1 Bcf	$4.06 Mcf	Basin Specific Swaps
	1.2 Bcf	$3.72 - $4.70 Mcf	Basin Specific Collars
2004	8.9 Bcf	$4.13 Mcf	NYMEX Swaps
	18.7 Bcf	$4.07 Mcf	Basin Specific Swaps
	2.4 Bcf	$4.05 - $4.44 Mcf	NYMEX Collars
2005	1.2 Bcf	$3.75 Mcf	NYMEX Swaps
	6.0 Bcf	$3.96 Mcf	Basin Specific Swaps
Natural Gas Basis Differential
2003	4.3 Bcf	**	Basis Swaps
Oil
2003	561 MBbl	$25.92 Bbl	NYMEX Swaps
2004	1,083 MBbl	$27.29 Bbl	NYMEX Swaps
	* 225 MBbl	$28.59 Bbl	NYMEX Swaps
Oil Basis Differential
2003	531 MBbl	**	Basis Swaps
2004	180 MBbl	**	Basis Swaps
Natural Gas Liquids
2003	9.5 MMGal	$0.42 Gal	Liquids Swaps
2004	37.2 MMGal	$0.41 Gal	Liquids Swaps
* Contracts entered into subsequent to September 30, 2003.
** Average contract prices 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. Production from continuing operations in 2003 is expected to approximate 85.3 Bcfe. As of December 31, 2002, the estimated amount of production from proved reserves was 82.7 Bcfe.

Operations and maintenance (O&M) expense increased $2.8 million for the quarter and $7.9 million in the year-to-date. Lease operating expenses (excluding production taxes) increased by $2.8 million for the quarter and $9 million year-to-date primarily due to the acquisition of oil and gas properties and increased drilling activity in the San Juan and Permian Basins as well as the coalbed methane down-spacing program. Exploration expense was higher by $0.5 million in the third quarter and decreased $1.3 million in year-to-date comparisons.

Energen Resources' depreciation, depletion and amortization (DD&A) expense for the quarter rose $1.5 million and $8.5 million in the year-to-date primarily as a result of increased production. The average depletion rate for the current quarter and year-to-date ended September 30, 2003, was $0.91 as compared to $0.92 in the same period a year ago.

Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $2 million higher this quarter and $7.9 million higher for the year-to-date largely due to significantly increased commodity market prices as well as increased production.

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 writedown 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," which was adopted as of January 1, 2002. In the current quarter, Energen Resources recorded a pre-tax gain of $0.5 million primarily from the sale of Gulf Coast properties as discussed below. In the year-to-date, Energen Resources recorded a pre-tax gain of $9.8 million from the sale of properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on certain non-strategic gas properties located in the Gulf Coast region, which were sold in August 2003. In the prior year quarter, Energen Resources recorded a pre-tax loss of $53,000. In the previous year-to-date, Energen Resources recorded a pre-tax gain of $3.3 million from the sale of properties and a pre-tax writedown of $2.8 million. The net gains (losses) from these transactions are included in total income from discontinued operations.

Natural Gas Distribution

Natural gas distribution revenues increased $7.9 million for the quarter largely due to an increase in the commodity cost of gas. For the quarter, weather was comparable with the previous period and residential sales volumes increased 1.5 percent over the same period last year. Small commercial and industrial customer sales volumes increased 13.6 percent while transportation volumes decreased 9.6 percent over the same period last year primarily due to higher gas prices which resulted in alternate fuel usage. Revenues for the year-to-date increased $51.1 million due to an increase in the commodity cost of gas as well as an increase in weather related usage. Weather that was 6.6 percent colder than in the same period last year contributed to a 9.2 percent increase in residential sales volumes and an 11.2 percent increase in small commercial and industrial customer sales volumes. For the same reasons that influenced the quarter, large transportation volumes decreased 6.4 percent. Higher commodity gas prices along with increased gas purchase volumes contributed to a 39.5 percent increase in cost of gas for the quarter and a 24.5 percent increase year-to-date. 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, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend the Company's rate-setting mechanism. 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.

O&M expense decreased 1.4 percent in the current quarter as lower bad debt expense was partially offset by increase labor related costs. In the year-to-date, O&M expense increased 4.4 percent primarily due to higher labor related and insurance costs. A 10.5 percent increase in depreciation expense in the current quarter and a 10 percent increase in the year-to-date period were due to normal growth of the utility's distribution system and replacement of support systems with higher depreciation rates than average rates applicable to the distribution system. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company decreased $0.8 million in the third quarter and $1.1 million for the year-to-date largely due to reduced long-term debt, decreased short-term debt borrowings due to a $32.2 million equity issuance completed in July 2003 and lower short-term interest rates in period comparisons.

In quarter comparisons, income tax expense increased $5.3 million primarily due to higher consolidated pre-tax income partially offset by a decrease of $1.2 million due to the interim reporting of non-conventional fuels tax credits recognized in the same period a year ago. In year-to-date comparisons, income tax expense rose $39.5 million due to higher pre-tax income and the recognition in the prior year of $10.4 million in non-conventional fuels tax credits. The Company's ability to generate non-conventional fuels tax credits on qualified production ended December 31, 2002, with the expiration of the credit.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $189.1 million as compared to $158.1 million in the same period last year. Increased net income during the period was augmented by changes in working capital items, which are highly influenced by throughput, changes in weather, and timing of payments. Working capital needs at Alagasco were primarily affected by storage gas inventory and increased gas costs compared to the prior period.

The Company had a net investment of $124.2 million through the nine months ended September 30, 2003, primarily in additions of property, plant and equipment. Energen Resources invested $113 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. In March 2003, Energen Resources completed its purchase of oil and gas properties located in the San Juan Basin for approximately $37 million. The Company gained an estimated 93 Bcfe of long-lived proved natural gas reserves associated with these acquisitions. Energen Resources sold certain properties in the current year-to-date resulting in cash proceeds of $29.1 million. Utility capital expenditures totaled $41 million in the year-to-date and primarily represented system distribution expansion and support facilities.

The Company used $64.9 million for financing activities in the year-to-date primarily due to the repayment of borrowings and dividends paid to common stockholders partially offset by proceeds from the issuance of common stock.

FUTURE CAPITAL RESOURCES AND LIQUIDITY

The Company plans to continue to implement its 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 calendar years ended December 31, 2002, Energen's diluted EPS grew at an average compound rate of 11.5 percent a year. Over the next five years, Energen is targeting an average EPS growth rate over each rolling five-year period of approximately 7 to 8 percent a year.

To finance Energen Resources' investment program, the Company expects to utilize short-term credit facilities to supplement internally generated cash flow, with long-term debt and equity providing permanent financing. Energen currently has available short-term credit facilities aggregating $267 million to help finance its growth plans and operating needs. As an acquisition company, 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. In February 2003, Moody's Investors Service confirmed Energen's debt rating as Baa1 and Alagasco's debt rating as A1. Standard and Poor's last update in October 2003, confirmed Energen's and Alagasco's rating as A- with a stable outlook. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets, continued accessibility could be affected by future economic and business conditions. Energen's management plans to utilize increases in cash flows to help finance Energen Resources' acquisition strategy. In July 2003, the Company completed a $32.2 million equity issuance through the periodic draw-down of shares in a shelf registration. In October 2003, the Company issued $50 million in long-term debt. These proceeds have been 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.

In 2003 Energen Resources plans to invest approximately $160 million to $165 million, including $37 million in property acquisitions and related development, approximately $120 million to $125 million in other development and approximately $1 million in exploratory activities. As of December 31, 2002, the estimated amount of development of previously identified proved undeveloped reserves was $65 million. Subject to adjustment as the Company completes its formal budgeting process, capital investment at Energen Resources in 2004 is expected to approximate $110 million for property acquisitions and related development and $85 million for other development and exploration. Of this $85 million, development of previously identified proved undeveloped reserves is estimated to be $35 million and exploratory exposure is estimated to be $1 million. Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2007, is estimated to be approximately $830 million, with $570 million for property acquisitions and related development, $235 million for other development and $25 million for exploratory and other activities. Of the $235 million, Energen Resources anticipates spending approximately $120 million on development of previously identified proved undeveloped reserves; of the $25 million, Energen Resources anticipates incurring approximately $15 million in exploratory exposure. Energen Resources' continued ability to invest in property acquisitions will be influenced significantly by industry trends, as the producing property acquisition market historically has been cyclical. 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 may pursue acquisitions that meet Energen's acquisition strategy. These acquisitions may alter the Company's financing requirements. Additionally, Energen Resources may enter into negotiations to sell, trade or otherwise dispose of properties which may modify the Company's financing needs.

An increase in national wholesale natural gas prices will increase natural gas costs for Alagasco customers for the 2003-2004 heating season as compared to the 2002-2003 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 March 1, 2003, Alagasco increased its rates to begin recovering these increased gas costs although such increases will not have a significant impact on most customers until the winter heating season.

During 2003, Alagasco plans to invest approximately $57 million in utility capital expenditures for normal distribution and support systems. Alagasco maintains an investment in storage gas that is expected to average approximately $36 million in 2003. Alagasco plans to invest approximately $55 million in utility capital expenditures during 2004. The utility anticipates funding these capital requirements through internally generated capital. Over the Company's five-year planning period ending December 31, 2007, Alagasco anticipates capital investments of approximately $265 million.

Certain of the Company's long-term contracts for the supply, storage and delivery of natural gas include fixed charges that amount to approximately $246.3 million through September 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 approximately 72.5 billion cubic feet through December 2006.

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 include regulated natural gas and crude oil futures contracts traded on the 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 Energen Resources or Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade status to have available counterparty credit.

Forward-Looking Statements and Risks

Certain statements in this report express expectations of future plans, objectives and performance of the Company and its subsidiaries and constitute forward-looking statements made pursuant to the Safe Harbor provision of the Private Securities Litigation Reform Act of 1995. Except as otherwise disclosed, the Company's forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. The Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. The Company undertakes no 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, future business decisions, and other uncertainties, all of which are difficult to predict.

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.

Although Energen Resources makes use of futures, swaps and fixed-price contracts to mitigate risk, fluctuations in future oil and gas prices could materially affect the Company's financial position, results of operation 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.

SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended		Nine months ended
	September 30,		September 30,
(in thousands, except sales price data)	2003	2002	2003	2002
Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$   59,627	$ 37,889	$  178,162	$ 103,309
Oil	21,213	19,958	65,119	51,006
Natural gas liquids	6,245	5,777	18,896	14,821
Other	909	995	4,119	2,507
Total	$   87,994	$ 64,619	$  266,296	$ 171,643
Production volumes from continuing operations
Natural gas (MMcf)	13,954	11,679	41,469	34,050
Oil (MBbl)	838	839	2,539	2,181
Natural gas liquids (MBbl)	395	455	1,179	1,246
Production volumes from continuing operations (MMcfe)	21,352	19,445	63,779	54,612
Total production volumes (MMcfe)	21,359	20,188	64,513	57,372
Average sales price including effects of hedging
Natural gas (Mcf)	$       4.27	$ 3.24	$        4.30	$ 3.03
Oil (barrel)	$     25.30	$ 23.78	$      25.64	$ 23.38
Natural gas liquids (barrel)	$     15.82	$ 12.70	$      16.03	$ 11.90
Average sales price excluding effects of hedging
Natural gas (Mcf)	$       4.79	$ 2.88	$        5.16	$ 2.76
Oil (barrel)	$     28.51	$ 26.40	$      29.38	$ 24.23
Natural gas liquids (barrel)	$     17.21	$ 12.70	$      18.26	$ 11.90
Other data from continuing operations
Lease operating expense (LOE)
LOE and other	$   16,666	$ 13,916	$    48,008	$ 38,955
Production taxes	$    6,764	$ 4,783	$    20,721	$ 12,841
Total	$   23,430	$ 18,699	$   68,729	$ 51,796
Depreciation, depletion and amortization	$   19,818	$ 18,281	$    59,941	$ 51,466
Capital expenditures	$   31,972	$ 25,639	$  112,994	$ 241,838
Exploration expenditures	$        802	$ 354	$      980	$ 2,294
Operating income	$   39,417	$ 22,464	$   123,068	$ 52,273
Natural Gas Distribution
Operating revenues
Residential	$   32,997	$ 27,829	$  246,382	$ 211,316
Commercial and industrial - small	17,844	13,214	97,556	79,550
Transportation	8,264	8,163	28,062	28,265
Other	(958)	1,019	1,534	3,327
Total	$   58,147	$ 50,225	$  373,534	$ 322,458
Gas delivery volumes (MMcf)
Residential	1,934	1,906	21,851	20,003
Commercial and industrial - small	1,625	1,430	9,998	8,991
Transportation	13,449	14,885	41,627	44,486
Total	17,008	18,221	73,476	73,480
Other data
Depreciation and amortization	$     9,385	$ 8,492	$    27,532	$ 25,035
Capital expenditures	$   13,177	$ 20,719	$    42,158	$ 50,455
Operating income (loss)	$    (9,575)	$ (8,907)	$    54,613	$ 48,625

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 Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. These counterparties have been deemed creditworthy by the Company and have agreed in certain instances to post collateral with the Company when unrealized gains on hedges exceed certain specified contractual amounts. Notwithstanding these agreements, the Company is at risk for economic loss based upon the credit worthiness of its counterparties. In some contracts, the amount of credit allowed before Energen Resources or Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade to have available counterparty credit. 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 is hedging exposures to the variability of cash flows is through December 31, 2005.

Energen Resources had certain agreements with Enron North America Corp. (Enron) as the counterparty as of October 1, 2001. As prescribed by SFAS No. 133, the value of the outstanding Enron contracts which qualified for cash flow hedge accounting treatment was reflected on the balance sheet as an asset and the effective portion of the derivative was reported as other comprehensive income. These outstanding contracts ceased to qualify as cash flow hedges during October 2001 as a result of Enron's credit issues. The Company recorded an expense to operations and maintenance for the write-down to fair value of the asset related to the effected derivative contracts. The deferred revenues related to the non-performing hedges were recorded in accumulated other comprehensive income until such time as they were reclassified to earnings as originally forecasted to occur. As a result, Energen's net income in the three-month transition period ended December 31, 2001, reflected a one-time, non-cash expense of $5.5 million, net of tax. Energen's net income reflected a non-cash benefit of $1.6 million, net of tax, for the three month period ended September 30, 2002, and a $5.6 million, net of tax, non-cash benefit for the nine month period ended September 30, 2002. Net income in the year ended December 31, 2002, reflected a total non-cash benefit of $5.7 million, net of tax, related to the Enron hedge position.

See Note 4 for details related to the Company's hedging activities.

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 significant 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 6. EXHIBITS AND REPORTS ON FORM 8-K
a.	Exhibits
	31(a) - Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31(b) - Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	32 - Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002
b.	Reports on Form 8-K
	Form 8-K dated July 18, 2003, reporting the sale of 1,000,000 shares of Energen common stock
	Form 8-K dated July 23, 2003, reporting Energen and Alagasco issued a press release announcing financial results for the second quarter of 2003

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 12, 2003	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 12, 2003	By   /s/ G. C. Ketcham
	G. C. Ketcham
	Executive Vice President, Chief
	Financial Officer and Treasurer of
	Energen Corporation and Alabama Gas
	Corporation
November 12, 2003	By   /s/ Grace B. Carr
	Grace B. Carr
	Vice President and Controller of Energen
	Corporation
November 12, 2003	By   /s/ Paula H. Rushing
	Paula H. Rushing
	Vice President-Finance of Alabama Gas
	Corporation

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