UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

| | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTER ENDED ____

OR

|X|  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM OCTOBER 1, 2001 TO DECEMBER 31, 2001

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 the number of shares outstanding of each of the issuers' classes of common stock, as of February 11, 2002:

Energen Corporation	$0.01 par value	31,241,887 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 DECEMBER 31, 2001
TABLE OF CONTENTS
		Page
PART I: FINANCIAL INFORMATION
Item 1.	Financial Statements
	(a) Consolidated Statements of Income of Energen Corporation	3
	(b) Consolidated Balance Sheets of Energen Corporation	4
	(c) Consolidated Statements of Cash Flows of Energen Corporation	6
	(d) Statements of Income of Alabama Gas Corporation	7
	(e) Balance Sheets of Alabama Gas Corporation	8
	(f) Statements of Cash Flows of Alabama Gas Corporation	10
	(g) Notes to Unaudited Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	16
	Selected Business Segment Data of Energen Corporation	20
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	21
	PART II: OTHER INFORMATION
Item 4.	Submission of Matters to a Vote of Security Holders	23
Item 6.	Exhibits and Reports on Form 8-K	23
SIGNATURES		24

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
Three months ended December 31, (in thousands, except per share data)	2001	2000

Operating Revenues
Oil and gas operations	$ 50,650	$ 56,771
Natural gas distribution	96,678	119,126
Total operating revenues	147,328	175,897
Operating Expenses
Cost of gas	45,291	67,183
Operations and maintenance	54,905	45,450
Depreciation, depletion and amortization	25,184	19,939
Taxes, other than income taxes	10,950	15,609
Total operating expenses	136,330	148,181
Operating Income	10,998	27,716
Other Income (Expense)
Interest expense	(10,634)	(10,240)
Other, net	(31)	663
Total other expense	(10,665)	(9,577)
Income Before Income Taxes	333	18,139
Income tax (benefit) expense	(3,325)	4,420
Net Income	$ 3,658	$  13,719
Diluted Earnings Per Average Common Share	$ 0.12	$      0.44
Basic Earnings Per Average Common Share	$ 0.12	$      0.45
Dividends Per Common Share	$ 0.175	$    0.17
Diluted Average Common Shares Outstanding	31,277	30,869
Basic Average Common Shares Outstanding	31,052	30,535

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

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
	December 31, 2001	September 30, 2001
(in thousands)	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$       6,482	$       5,333
Accounts receivable, net of allowance for doubtful     accounts of $11,623 at December 31, 2001, and     $10,031 at September 30, 2001	77,106	74,078
Inventories, at average cost
Storage gas inventory	50,978	56,761
Materials and supplies	8,894	10,225
Liquified natural gas in storage	3,146	3,271
Deferred gas costs	17,776	3,275
Deferred income taxes	29,636	12,425
Prepayments and other	6,948	27,176
Total current assets	200,966	192,544
Property, Plant and Equipment
Oil and gas properties, successful efforts method	844,962	822,956
Less accumulated depreciation, depletion and amortization	228,867	209,451
Oil and gas properties, net	616,095	613,505
Utility plant	769,259	758,374
Less accumulated depreciation	384,430	378,218
Utility plant, net	384,829	380,156
Other property, net	4,755	4,673
Total property, plant and equipment, net	1,005,679	998,334
Other Assets
Deferred income taxes	8,406	12,039
Deferred charges and other	25,305	20,962
Total other assets	33,711	33,001
TOTAL ASSETS	$   1,240,356	$   1,223,879

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

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
	December 31, 2001	September 30, 2001
(in thousands, except share data)	(Unaudited)
CAPITAL AND LIABILITIES
Current Liabilities
Long-term debt due within one year	$      16,072	$      16,072
Notes payable to banks	24,000	7,000
Accounts payable	58,783	65,412
Accrued taxes	32,183	30,014
Customers' deposits	16,399	15,195
Amounts due customers	14,896	3,792
Accrued wages and benefits	22,711	25,821
Other	29,564	32,217
Total current liabilities	214,608	195,523
Deferred Credits and Other Liabilities
Other	7,410	3,479
Total deferred credits and other liabilities	7,410	3,479
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,      31,248,547 shares outstanding at December 31, 2001, and      31,124,761 shares outstanding at September 30, 2001	312	311
Premium on capital stock	235,976	233,471
Capital surplus	2,802	2,802
Retained earnings	230,554	232,354
Accumulated other comprehensive income, net of tax	7,168	15,531
Deferred compensation on restricted stock	(1,513)	(1,186)
Deferred compensation plan	7,222	5,259
Treasury stock, at cost (341,465 shares at December 31, 2001,     and 325,355 shares at September 30, 2001)	(8,316)	(7,775)
Total common shareholders' equity	474,205	480,767
Long-term debt	544,133	544,110
Total capitalization	1,018,338	1,024,877
TOTAL CAPITAL AND LIABILITIES	$   1,240,356	$   1,223,879

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Three months ended December 31, (in thousands)	2001	2000
Operating Activities
Net income	$    3,658	$    13,719
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization	25,184	19,939
Deferred income taxes	(8,495)	3,545
Deferred investment tax credits	(112)	(112)
Change in derivative fair value	(174)	2,269
Loss (gain) on sale of assets	3,161	(823)
Net change in:
Accounts receivable	(3,028)	(47,578)
Inventories	7,239	14,742
Deferred gas costs	(14,501)	(35,062)
Accounts payable	2,442	48,892
Amounts due customers	11,637	(850)
Other current assets and liabilities	(4,813)	(416)
Other, net	(843)	2,427
Net cash provided by operating activities	21,355	20,692
Investing Activities
Additions to property, plant and equipment	(37,752)	(19,626)
Proceeds from sale of assets	2,323	5,979
Other, net	(252)	(323)
Net cash used in investing activities	(35,681)	(13,970)
Financing Activities
Payment of dividends on common stock	(5,452)	(5,200)
Issuance of common stock	5,172	9,109
Purchase of treasury stock	(1,245)	-
Reduction of long-term debt	-	(4,684)
Proceeds from issuance of long-term debt	-	148,799
Debt issuance costs	-	(975)
Net change in short-term debt	17,000	(146,000)
Net cash provided by financing activities	15,475	1,049
Net change in cash and cash equivalents	1,149	7,771
Cash and cash equivalents at beginning of period	5,333	3,823
Cash and Cash Equivalents at End of Period	$     6,482	$     11,594

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

STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
Three months ended December 31, (in thousands)	2001	2000

Operating Revenues	$ 96,678	$ 119,126
Operating Expenses
Cost of gas	45,651	67,679
Operations and maintenance	27,687	26,837
Depreciation	8,151	7,554
Income taxes
Current	10,348	2,888
Deferred, net	(8,689)	(682)
Deferred investment tax credits, net	(112)	(112)
Taxes, other than income taxes	7,155	8,464
Total operating expenses	90,191	112,628
Operating Income	6,487	6,498
Other Income (Expense)
Allowance for funds used during construction	122	534
Other, net	(242)	(42)
Total other income	(120)	492
Interest Charges
Interest on long-term debt	3,327	2,123
Other interest expense	353	827
Total interest charges	3,680	2,950
Net Income	$ 2,687	$ 4,040

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

BALANCE SHEETS
ALABAMA GAS CORPORATION
	December 31, 2001	September 30, 2001
(in thousands)	(Unaudited)
ASSETS
Property, Plant and Equipment
Utility plant	$     769,259	$     758,374
Less accumulated depreciation	384,430	378,218
Utility plant, net	384,829	380,156
Other property, net	308	333
Current Assets
Cash and cash equivalents	3,372	1,555
Accounts receivable
Gas	59,504	47,024
Merchandise	1,506	1,417
Other	626	1,448
Affiliated companies	-	937
Allowance for doubtful accounts	(11,100)	(9,500)
Inventories, at average cost
Storage gas inventory	50,978	56,761
Materials and supplies	5,363	5,423
Liquified natural gas in storage	3,146	3,271
Deferred gas costs	17,776	3,275
Deferred income taxes	22,820	14,477
Prepayments and other	1,378	2,616
Total current assets	155,369	128,704
Deferred Charges and Other Assets	8,715	8,546
TOTAL ASSETS	$   549,221	$   517,739

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

BALANCE SHEETS
ALABAMA GAS CORPORATION
	December 31, 2001	September 30, 2001
(in thousands, except share data)	(Unaudited)
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         December 31, 2001, and September 30, 2001	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	172,147	174,885
Total common shareholder's equity	206,651	209,389
Long-term debt	185,000	185,000
Total capitalization	391,651	394,389
Current Liabilities
Long-term debt due within one year	5,000	5,000
Notes payable to banks	19,000	1,000
Accounts payable	37,077	32,078
Accrued taxes	29,505	26,963
Customers' deposits	16,399	15,195
Amounts due customers	14,896	3,792
Accrued wages and benefits	10,509	11,616
Other	7,289	9,416
Total current liabilities	139,675	105,060
Deferred Credits and Other Liabilities
Deferred income taxes	15,531	15,825
Accumulated deferred investment tax credits	1,204	1,317
Regulatory liability	137	242
Customer advances for construction and other	1,023	906
Total deferred credits and other liabilities	17,895	18,290
Commitments and Contingencies
TOTAL CAPITAL AND LIABILITIES	$   549,221	$   517,739

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

STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Three months ended December 31, (in thousands)	2001	2000
Operating Activities
Net income	$       2,687	$      4,040
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization	8,151	7,554
Deferred income taxes, net	(8,689)	(682)
Deferred investment tax credits	(112)	(112)
Net change in:
Accounts receivable	(10,147)	(36,749)
Inventories	5,968	14,849
Deferred gas costs	(14,501)	(35,062)
Accounts payable	1,945	46,918
Amounts due customers	11,637	(850)
Other current assets and liabilities	1,191	2,763
Other, net	(201)	(719)
Net cash provided by (used in) operating activities	(2,071)	1,950
Investing Activities
Additions to property, plant and equipment	(12,820)	(9,506)
Other, net	143	(74)
Net cash used in investing activities	(12,677)	(9,580)
Financing Activities
Dividends	(5,426)	-
Net advances from affiliates	3,991	19,027
Reduction of long-term debt	-	(4,650)
Net change in short-term debt	18,000	1,500
Net cash provided by financing activities	16,565	15,877
Net change in cash and cash equivalents	1,817	8,247
Cash and cash equivalents at beginning of period	1,555	866
Cash and Cash Equivalents at End of Period	$    3,372	$     9,113

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

NOTES TO UNAUDITED FINANCIAL STATEMENTS

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

1. BASIS OF PRESENTATION

All 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. The unaudited financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended September 30, 2001, 2000, and 1999, included in the 2001 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Certain reclassifications were made to conform prior years' financial statements to the current-quarter presentation. The Company's natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for the interim periods are not necessarily indicative of the results that may be expected for the year.

On December 5, 2001, the Board of Directors of the Company made a determination to change the registrants' fiscal year end from September 30 to December 31. The period from October 1, 2001 to December 31, 2001 is a transition quarter in changing Energen's fiscal year to coincide with the calendar year. Alagasco will continue on a September 30 fiscal year for rate-setting purposes (rate year) and will report on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes.

2. REGULATORY

As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which, in 1983, established the Rate Stabilization and Equalization (RSE) rate-setting process. RSE was extended with modifications in 1990, 1987 and 1985. On October 7, 1996, RSE was extended, without change, for a five-year period and will continue, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. 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. 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. Under RSE as extended, a $16.3 million and a $9.1 million annual increase in revenues became effective December 1, 2001 and 2000, respectively.

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. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. 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 October 1997 in the amount of $3.9 million 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. During 2001, Alagasco charged $1.2 million against the ESR related to extraordinary bad debt expense and revenue losses from certain large industrial customers. 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 De cember 31, 2001, and September 30, 2001, the ESR balance of $2.7 million was included in the consolidated financial statements.

3. DERIVATIVE COMMODITY INSTRUMENTS

The Company adopted Statement of Financial Accounting Standard (SFAS) No. 133 (subsequently amended by SFAS Nos. 137 and 138), Accounting for Derivative Instruments and Hedging Activities, on October 1, 2000. This statement 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 into earnings 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 to hedge its exposure to price fluctuations on oil and gas 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 and basis hedges with major energy derivative product specialists. The Company has identified certain oil and gas derivatives which qualify as cash flow hedges under SFAS No. 133.

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, a component of shareholders' equity. 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 are recorded in OCI until such time as they are reclassified to earnings as originally forecasted to occur. As a result, Energen's net income in the three-month period ended December 31, 2001, reflected a one-time, non-cash expense of $5.5 million, net of tax, and its net i ncome in the year ended December 31, 2002, will reflect a non-cash benefit of $5.9 million, net of tax, related to Enron's hedge position.

As of December 31, 2001, $7.5 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, including the $5.9 million related to the Enron transactions, are expected to be reclassified to earnings during the next twelve-month period. Gains and losses on derivative instruments that are not accounted for as cash flow hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. The Company recorded an after-tax loss of $73,000 for the three-months ended December 31, 2001, for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, Energen Resources recorded an after-tax gain of $106,000 for the quarter on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of December 31, 2001, the Company had 0.9 bill ion cubic feet (Bcf) of gas basis hedges that did not meet the definition of a cash flow hedge. As of December 31, 2001, and September 30, 2001, the Company had $5.9 million and $9.9 million, respectively, included in deferred income taxes on the consolidated balance sheets related to other comprehensive income.

As of December 31, 2001, Energen Resources had basin-specific hedges in place for 0.5 Bcf of its estimated 2002 gas production at an average contract price of $3.77 per Mcf and 0.6 Bcf of gas production hedged at a NYMEX collar price of $4.25 to $6.15 per Mcf. Energen Resources also had hedges in place for 150 thousand barrels (MBbl) of its estimated oil production at an average NYMEX price of $27.38 per barrel. In addition, the Company had hedged the basis difference on 0.9 Bcf of its estimated 2002 gas production. Realized prices are anticipated to be lower than NYMEX prices due to basis difference and other factors. Production estimates for 2002 total 73 Bcfe, including 50.1 Bcf of gas, 2.1 MMBbl of oil and 1.7 MMBbl of natural gas liquids. These estimates include 5.5 Bcfe of production from anticipated acquisitions and exploration activity.

As of December 31, 2001, Energen Resources had entered into basin-specific swaps for 1.4 Bcf of its gas production in 2003 at an average contract price of $3.77 per Mcf and swaps for 0.5 Bcf of its 2003 gas production at an average NYMEX price of $3.77 per Mcf. For 2004 and 2005, Energen Resources had entered into swaps for 1.7 Bcf and 1.2 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively.

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 is not determined to be highly effective as a hedge or it has ceased to be a highly effective hedge. The maximum term over which Energen Resources is hedging exposures to the variability of cash flows is through September 30, 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 of December 31, 2001, and September 30, 2001, Alagasco had recorded a $378,000 asset and a $117,000 liability, respectively, representing the fair value of derivatives. As required by SFAS No. 133, Alagasco recognizes all derivatives 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 accordance with Alagasco's APSC-approved tariff.

4. RECENT PRONOUNCEMENTS OF THE FASB

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company is required to adopt this statement in 2003. The impact of this pronouncement on the Company currently is being evaluated and is not expected to be material. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which addresses accounting and reporting standards for long-lived assets. The Company adopted this statement on January 1, 2002; the impact of this pronouncement on the Company is not material.

5. RECONCILIATION OF EARNINGS PER SHARE

		Three months ended				Three months ended
(in thousands, except per share amounts)		December 31, 2001				December 31, 2000
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount
Basic EPS	$   3,658		31,052	$  0.12	$  13,719		30,535	$  0.45
Effect of Dilutive Securities
Long-range performance shares			97				94
Stock options			127				240
Restricted stock			1				-
Diluted EPS	$   3,658		31,277	$  0.12	$  13,719		30,869	$  0.44

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
	December 31,
(in thousands)	2001	2000
Operating revenues
Oil and gas operations	$ 50,650	$ 56,771
Natural gas distribution	96,678	119,126
Total	$ 147,328	$ 175,897
Operating income (loss)
Oil and gas operations	$ 3,381	$ 19,572
Natural gas distribution	8,034	8,592
Eliminations and corporate expenses	(417)	(448)
Total	$ 10,998	$ 27,716

(in thousands)	December 31, 2001	September 30, 2001
Identifiable assets
Oil and gas operations	$ 687,776	$ 716,043
Natural gas distribution	549,221	516,802
Eliminations and other	3,359	(8,966)
Total	$ 1,240,356	$ 1,223,879

7. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended	Three months ended
(in thousands)	December 31, 2001	December 31, 2000
Net Income	$     3,658	$    13,719
Other comprehensive income (loss)
Transition adjustment on cash flow hedging taxes, net of tax of ($35.4) million	-	(55,416)
Current period change in fair value of derivative instruments, net of tax of ($0.2) million and ($21.3) million	(292)	(33,303)
Reclassification adjustment, net of tax of ($3.8) million and $11.4 million	(5,977)	17,802
Minimum pension liability, net of tax of ($1.1) million	(2,094)	-
Comprehensive Income (Loss)	$   (4,705)	$    (57,198)

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

(in thousands)	December 31, 2001	September 30, 2001
Unrealized gain (loss) on hedges, net of tax of $5.9 million	$ 9,262	$ 15,531
Minimum pension liability, net of tax of ($1.1) million	(2,094)	-
Accumulated Other Comprehensive Income	$ 7,168	$ 15,531

8. BUISNESS RELATIONSHIP WITH ENRON

Enron filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code on December 2, 2001. In the days leading up to the bankruptcy filing, various events occurred which caused Enron to be in default under all of its agreements with Energen Resources and most of its agreements with Alagasco. These agreements provided Energen Resources and Alagasco with various remedies including, termination and liquidation rights in the event of such defaults. Energen Resources and Alagasco have and will continue to take the steps that they deem appropriate to avail themselves of the default remedies under the various agreements including setting off the amounts owed by Alagasco to Enron against amounts owed to Energen Resources by Enron. Enron owed Energen Resources $4.9 million for gas purchased by Enron, and Alagasco owed Enron approximately $7.8 million for gas purchased by Alagasco. The Company applied its rights of set off for these amounts and $2.9 million representing a p ortion of the amounts Enron owed Energen Resources for the value of derivative contracts. (See Note 3.) Such set off has been reflected in the accompanying financial statements for the three-months ended December 31, 2001.

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

RESULTS OF OPERATIONS

Energen's net income totaled $3.7 million ($0.12 per diluted share) for the three months ended December 31, 2001, compared to net income of $13.7 million ($0.44 per diluted share) recorded in the same period last year. Energen Resources Corporation, Energen's oil and gas subsidiary, realized net income of $1.1 million in the current transition quarter as compared with $9.9 million in the same quarter last year largely due to a one-time non-cash write-off of $5.5 million after-tax, or $0.17 per diluted share, associated with its hedge position with Enron North America Corp. (Enron), as more fully described in Note 3. (The accounting treatment related to Enron will result in a non-cash benefit of approximately $0.18 per diluted share for 2002.) Also negatively impacting net income were increased depreciation, depletion and amortization (DD&A) expense, a $1.7 million writedown on property held for sale and lower natural gas liquids prices. Energen's natural gas utility, Alagasco, reported net income of $2.7 million in the transition quarter as compared to $4 million in the same period last year primarily due to increased bad debt expense as well as a decline in cycle and industrial gas usage.

On December 5, 2001, the Board of Directors of the Company made a determination to change the registrants' fiscal year end from September 30 to December 31. The period from October 1, 2001 to December 31, 2001 is a transition quarter in changing Energen's fiscal year to coincide with the calendar year. Alagasco will continue on a September 30 fiscal year for rate-setting purposes (rate year) and will report on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes.

Oil and Gas Operations

Revenues from oil and gas operations declined 10.8 percent to $50.7 million for the three months ended December 31, 2001, largely as a result of lower natural gas liquids prices. In the transition quarter, realized gas prices increased slightly to $2.97 per Mcf, while realized oil prices rose 5.9 percent to $24.03 per barrel. Natural gas liquids prices decreased 51.3 percent to an average price of $10.08 per barrel.

Natural gas production in the transition quarter increased slightly to 12 Bcf, while oil volumes decreased slightly to 550 MBbl. Natural gas liquids production increased 13.3 percent to 451 MBbl. Natural gas comprised nearly 70 percent of Energen Resources' production for the current quarter.

Energen Resources enters into derivative commodity instruments to hedge its exposure to the impact of price fluctuations on oil and gas 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 and basis hedges with major energy derivative product specialists. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions.

As more fully discussed in Note 3, Energen Resources had certain swap agreements with Enron as the counterparty as of October 1, 2001. These swap agreements ceased to qualify as cash flow hedges during October 2001 as a result of Enron's credit issues. As of December 31, 2001, Energen Resources had basin-specific hedges in place for 0.5 Bcf of its estimated 2002 gas production at an average contract price of $3.77 per Mcf and 0.6 Bcf of gas production hedged at a NYMEX collar price of $4.25 to $6.15 per Mcf. Energen Resources also had hedges in place for 150 MBbl of its estimated oil production at an average NYMEX price of $27.38 per barrel. In addition, the Company had hedged the basis difference on 0.9 Bcf of its 2002 gas production. Realized prices are anticipated to be lower than NYMEX prices due to basis difference and other factors. Production estimates for 2002 total 73 Bcfe, including 50.1 Bcf of gas, 2.1 MMBbl of oil and 1.7 MMBbl of natural gas liquids. These estimates include 5. 5 Bcfe of production from anticipated acquisitions and exploration activity.

As of December 31, 2001, Energen Resources had entered into basin-specific swaps for 1.4 Bcf of its gas production in 2003 at an average contract price of $3.77 per Mcf and swaps for 0.5 Bcf of its 2003 gas production at an average NYMEX price of $3.77 per Mcf. For 2004 and 2005, Energen Resources had entered into swaps for 1.7 Bcf and 1.2 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively.

Energen Resources, in the ordinary course of business, may be involved in the sale of developed and undeveloped non-strategic properties. Gains or losses on the sale of such properties are included in operating revenues. Energen Resources recorded a pre-tax loss of $3.4 million for the current transition quarter from the sale of properties and adjustments to the fair value of properties held for sale as compared to a pre-tax gain of $0.8 million in the prior year quarter on the sale of various properties.

Operations and maintenance (O&M) expense increased $8.6 million for the quarter largely due to the one-time non-cash write-off of $8.7 million pre-tax associated with Energen Resources' hedge position with Enron. Lease operating expenses increased by $0.7 million for the quarter while exploration expense remained relatively stable.

Energen Resources' DD&A expense for the quarter rose $4.6 million primarily driven by market declines in commodity prices. The average depletion rate for the transition quarter was $0.93 as compared to $0.68 for the same period last year.

Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $3.3 million lower this quarter primarily as a result of the significantly decreased commodity market prices.

Natural Gas Distribution

Natural gas distribution revenues decreased $22.4 million for the quarter largely due to a decrease in the commodity cost of gas as well as to a decrease in weather-related sales volumes and gas usage volumes. For the quarter, weather that was 30.1 percent warmer than the same period last year contributed to a 29.1 percent decrease in residential sales volumes and a 34.3 percent decrease in small commercial and industrial customer sales volumes. Transportation volumes decreased 6.3 percent primarily due to reduced consumption resulting from a general economic weakness in the current period. Lower commodity gas prices along with decreased gas purchase volumes contributed to a 32.5 percent decrease in cost of gas for the quarter. The GSA rider in Alagasco's rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco calculates a temperature adjustment to certain customers' bills on a real-time basis to substantially remove the effect of depar tures from normal temperatures. The customers to whom the temperature adjustment applies primarily are residential, small commercial and small industrial.

As discussed more fully in Note 2, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On October 7, 1996, the APSC issued an order to extend the Company's rate-setting mechanism through January 1, 2002. Under the terms of that extension, RSE will continue after January 1, 2002, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation.

O&M expense increased 3.2 percent in the transition quarter primarily due to increased bad debt expense partially offset by reduced labor related and marketing costs. A 7.9 percent increase in depreciation expense in the current quarter primarily was due to normal growth of the utility's 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 increased $0.4 million for the quarter. Influencing the increase in interest expense for the current quarter was the issuance of $150 million of Medium Term Notes issued by Energen in December 2000 and the issuance by Alagasco of $40 million of 6.25% Notes and $35 million of 6.75% Notes in August 2001. The proceeds from the Notes were used for repayment of borrowings under Energen's short-term credit facilities incurred as a result of the growth at Energen Resources and for general corporate purposes at Alagasco.

The Company's effective tax rates are lower than statutory federal tax rates primarily due to the recognition of nonconventional fuels tax credits and the amortization of investment tax credits. Nonconventional fuels tax credits are generated annually on qualified production through December 31, 2002, and effective tax rates are expected to continue to remain lower than statutory federal rates through December 31, 2002.

Income tax expense decreased in quarter comparisons primarily as a result of lower consolidated pre-tax income slightly offset by higher nonconventional fuels tax credits of $1.2 million. The increase in credit recognition reflected the annualized effective rate applied on an interim basis in the prior year as compared to the transition period which was presented as a stand alone tax period in the current quarter. The effective tax rate utilized in computing income tax expense reflects financial recognition of $3.5 million of nonconventional fuels tax credits as produced during the transitional quarter.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the current transition quarter were $21.4 million compared to $20.7 million in the same period last year. The decreased net income during the period was offset by changes in working capital items, which are highly influenced by throughput, changes in weather, and timing of payments.

The Company had a net investment of $35.7 million through the three months ended December 31, 2001, primarily in additions of property, plant and equipment. Energen Resources invested $25.1 million in capital expenditures primarily related to the development of oil and gas properties. Utility capital expenditures totaled $12.9 million in the quarter and primarily represented system distribution expansion and support facilities. The Company had cash proceeds of $2.3 million resulting from the sale of certain properties during the transition period.

The Company's financing activities provided $15.5 million for the current quarter in net cash flows. Increased borrowings under Energen's short-term credit facilities were used to finance Energen Resources' acquisition strategy and general corporate needs at Alagasco.

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 and exploitation of producing properties with development potential while building on the strength of the Company's utility foundation. For the five-years ended December 31, 2001, Energen's diluted EPS grew at an average compound rate of 13.1 percent a year.

To finance Energen Resources' investment program, the Company will continue to utilize its 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 of $225 million to help accommodate its growth plans. Energen's management plans to utilize increases in cash flows to help finance Energen Resources' acquisition and exploitation strategy and to help reduce Energen's debt-to-total capitalization ratio to below 50 percent over the next five years.

In 2002, Energen Resources plans to invest approximately $220 million in capital expenditures, including $125 million for the property acquisitions and $78 million in related exploitation activities. Energen Resources' exploratory exposure in 2002 is estimated to be $5 million, along with additional associated development. Capital investment at Energen Resources in 2003 is expected to approximate $50 million for acquisitions, $65 million for exploitation and $10 million for exploration and related development. Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2006, is estimated to range from $800 million to $850 million. During this period, the Company expects to issue approximately $50 million in additional long-term debt to replace short-term obligations and provide permanent financing for Energen Resources' acquisition strategy. The Company will also provide up to $13 million a year from the issuance of common stock through th e dividend reinvestment and direct stock purchase plan and the employee savings plans. 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. From time to time, Energen Resources also may be engaged in negotiations to sell, trade or otherwise dispose of properties.

During 2002, Alagasco plans to invest approximately $64 million in utility capital expenditures for normal distribution and support systems, including approximately $22 million for revenue-producing main projects and $10 million for information technology application projects. Alagasco also maintains an investment in storage gas which is expected to average approximately $34 million in 2002. Alagasco plans to invest approximately $56 million in utility capital expenditures during 2003. The utility anticipates funding these capital requirements through internally generated capital and approximately $50 million of long-term debt. Over the Company's five-year planning period ending December 31, 2006, Alagasco anticipates capital investments of approximately $275 million.

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. We undertake 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 affect materially the Com pany's financial position and results of operation; 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. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts.

SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
Three months ended December 31, (in thousands, except sales price data)	2001		2000
Oil and Gas Operations
Operating revenues
Natural gas	$ 35,635		$ 35,317
Oil	13,215		12,708
Natural gas liquids	4,546		8,235
Other	(2,746)		511
Total	$ 50,650		$ 56,771
Sales Volumes
Natural gas (MMcf)	12,018		11,947
Oil (MBbl)	550		560
Natural gas liquids (MBbl)	451		398
Average sales price
Natural gas (Mcf)	$ 2.97		$ 2.96
Oil (barrel)	$ 24.03		$ 22.69
Natural gas liquids (barrel)	$ 10.08		$ 20.68
Other data
Depreciation, depletion and amortization	$ 17,033		$ 12,385
Capital expenditures	$ 25,052		$ 10,087
Exploration expenditures	$ 827		$ 1,085
Operating income	$ 3,381		$ 19,572
Natural Gas Distribution
Operating revenues
Residential		$ 63,724	$ 77,475
Commercial and industrial - small		22,445	31,036
Transportation		9,765	9,516
Other		744	1,099
Total		$ 96,678	$ 119,126
Gas delivery volumes (MMcf)
Residential		5,128	7,230
Commercial and industrial - small		2,193	3,337
Transportation		12,973	13,851
Total		20,294	24,418
Other data
Depreciation and amortization		$ 8,151	$ 7,554
Capital expenditures		$ 12,873	$ 10,126
Operating income		$ 8,034	$ 8,592

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.

The Company adopted Statement of Financial Accounting Standard (SFAS) No. 133 (subsequently amended by SFAS Nos. 137 and 138), Accounting for Derivative Instruments and Hedging Activities, on October 1, 2000. This statement 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 as a component of equity and subsequently reclassified into earnings 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 record ed 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 to hedge its exposure to price fluctuations on oil and gas 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 and basis hedges with major energy derivative product specialists. The Company has identified certain oil and gas derivatives which qualify as cash flow hedges under SFAS No. 133.

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, a component of shareholders' equity. 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 are recorded in OCI until such time as they are reclassified to earnings as originally forecasted to occur. As a result, Energen's net income in the three-month period ended December 31, 2001, reflected a one-time, non-cash expense of $5.5 million, net of tax, and its net i ncome in the year ended December 31, 2002, will reflect a non-cash benefit of $5.9 million, net of tax, related to Enron's hedge position.

As of December 31, 2001, $7.5 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, including the $5.9 million related to the Enron transactions, are expected to be reclassified to earnings during the next twelve-month period. Gains and losses on derivative instruments that are not accounted for as cash flow hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. The Company recorded an after-tax loss of $73,000 for the three-months ended December 31, 2001, for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, Energen Resources recorded an after-tax gain of $106,000 for the quarter on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of December 31, 2001, the Company had 0.9 Bcf of gas basis hedges that did not meet the definition of a cash flow hedge. As of December 31, 2001 and September 30, 2001, the Company had $5.9 million and $9.9 million, respectively, included in deferred income taxes on the consolidated balance sheets related to other comprehensive income.

As of December 31, 2001, Energen Resources had basin-specific hedges in place for 0.5 Bcf of its estimated 2002 gas production at an average contract price of $3.77 per Mcf and 0.6 Bcf of gas production hedged at a NYMEX collar price of $4.25 to $6.15 per Mcf. Energen Resources also had hedges in place for 150 MBbl of its estimated oil production at an average NYMEX price of $27.38 per barrel. In addition, the Company had hedged the basis difference on 0.9 Bcf of its estimated 2002 gas production. Realized prices are anticipated to be lower than NYMEX prices due to basis difference and other factors. Production estimates for 2002 total 73 Bcfe, including 50.1 Bcf of gas, 2.1 MMBbl of oil and 1.7 MMBbl of natural gas liquids. These estimates include 5.5 Bcfe of production from anticipated acquisitions and related exploration activity.

As of December 31, 2001, Energen Resources had entered into basin-specific swaps for 1.4 Bcf of its gas production in 2003 at an average contract price of $3.77 per Mcf and swaps for 0.5 Bcf of its 2003 gas production at an average NYMEX price of $3.77 per Mcf. For 2004 and 2005, Energen Resources had entered into swaps for 1.7 Bcf and 1.2 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively.

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 is not determined to be highly effective as a hedge or it has ceased to be a highly effective hedge. The maximum term over which Energen Resources is hedging exposures to the variability of cash flows is through September 30, 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 of December 31, 2001, and September 30, 2001, Alagasco had recorded a $378,000 asset and a $117,000 liability, respectively, representing the fair value of derivatives. As required by SFAS No. 133, Alagasco recognizes all derivatives 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 accordance with Alagasco's APSC-approved tariff.

PART II. OTHER INFORMATION

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

a. At the annual meeting of shareholders held on January 30, 2002, Energen shareholders elected the following Directors to serve for three year terms expiring in 2005:

Director Votes cast for Votes withheld

J. Mason Davis, Jr. 24,286,497 1,205,174

James S.M. French 24,323,074 1,168,597

Wallace L. Luthy 24,308,430 1,183,241

b. At the annual meeting of shareholders held on January 30, 2002, Energen shareholders elected to approve an amendment to the Company's 1997 Stock Incentive Plan to (i) increase the number of shares reserved for issuance thereunder, and (ii) amend the limitation on awards to any one participant, and to qualify such plan for purposes of Section 162 (m) of the Internal Revenue Code of 1986, as amended:

Votes cast for Votes against Votes withheld

15,183,045 9,965,250 343,376

c. At the annual meeting of shareholders held on January 30, 2002, Energen shareholders elected to approve the Company's Annual Incentive Compensation Plan:

Votes cast for Votes against Votes withheld

23,377,572 1,757,957 356,142

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a. Exhibits

10(a) Energen Corporation 1997 Stock Incentive Plan (as amended effective January 30, 2002) which was filed on December 27, 2001, as Appendix A to Energen's Proxy Statement form Def 14A (File No. 1-7810)

10(b) Energen Corporation Annual Incentive Compensation Plan (January 1, 2002) which was filed on December 27, 2001, as Appendix B to Energen's Proxy Statement form Def 14A (File No. 1-7810)

b. Reports on Form 8-K

Form 8-K dated December 11, 2001, reporting Energen's determination to change the Company's fiscal year end from September 30 to December 31

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
February 13, 2002	By   /s/ Wm. Michael Warren, Jr.
	Wm. Michael Warren, Jr.
	Chairman, President and Chief Executive
	Officer of Energen, Chairman and Chief
	Executive Officer of Alabama Gas
	Corporation
February 13, 2002	By   /s/ G. C. Ketcham
	G. C. Ketcham
	Executive Vice President, Chief
	Financial Officer and Treasurer of
	Energen and Alabama Gas Corporation
February 13, 2002	By   /s/ Grace B. Carr
	Grace B. Carr
	Vice President and Controller of Energen
February 13, 2002	By   /s/ Paula H. Rushing
	Paula H. Rushing
	Vice President-Finance of Alabama Gas
	Corporation

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