Energen (EGN) 10-Q 2002 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

FORM 10-Q

|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTER ENDED MARCH 31, 2002

OR

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

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

605 Richard Arrington Jr. Boulevard North

Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

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

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

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of May 13, 2002:

Energen Corporation	$0.01 par value	34,386,347 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 MARCH 31, 2002
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 March 31,(in thousands, except per share data)	2002	2001

Operating Revenues
Oil and gas operations	$ 47,859	$ 63,194
Natural gas distribution	196,524	270,286
Total operating revenues	244,383	333,480
Operating Expenses
Cost of gas	96,148	174,136
Operations and maintenance	46,285	46,264
Depreciation, depletion and amortization	24,849	20,551
Taxes, other than income taxes	16,317	23,809
Total operating expenses	183,599	264,760
Operating Income	60,784	68,720
Other Income (Expense)
Interest expense	(10,669)	(10,606)
Other, net	61	345
Total other expense	(10,608)	(10,261)
Income Before Income Taxes	50,176	58,459
Income tax expense	11,186	11,467
Net Income	$ 38,990	$  46,992
Diluted Earnings Per Average Common Share	$ 1.24	$      1.52
Basic Earnings Per Average Common Share	$ 1.25	$      1.53
Dividends Per Common Share	$ 0.175	$    0.17
Diluted Average Common Shares Outstanding	31,421	30,997
Basic Average Common Shares Outstanding	31,180	30,662

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

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	March 31, 2002	December 31, 2001
ASSETS
Current Assets
Cash and cash equivalents	$       14,794	$       6,482
Accounts receivable, net of allowance for doubtful     accounts of $11,591 at March 31, 2002, and     $11,623 at December 31, 2001	89,666	77,106
Inventories, at average cost
Storage gas inventory	18,963	50,978
Materials and supplies	8,847	8,894
Liquified natural gas in storage	2,854	3,146
Deferred gas costs	9,476	17,776
Amounts due from customers	7,045	-
Deferred income taxes	32,250	29,636
Prepayments and other	6,420	6,948
Total current assets	190,315	200,966
Property, Plant and Equipment
Oil and gas properties, successful efforts method	859,765	844,962
Less accumulated depreciation, depletion and amortization	238,544	228,867
Oil and gas properties, net	621,221	616,095
Utility plant	781,895	769,259
Less accumulated depreciation	391,575	384,430
Utility plant, net	390,320	384,829
Other property, net	4,548	4,755
Total property, plant and equipment, net	1,016,089	1,005,679
Other Assets
Deferred income taxes	7,789	8,406
Deferred charges and other	28,760	25,305
Total other assets	36,549	33,711
TOTAL ASSETS	$   1,242,953	$   1,240,356

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

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands, except share data)	March 31, 2002	December 31, 2001
CAPITAL AND LIABILITIES
Current Liabilities
Long-term debt due within one year	$      16,109	$      16,072
Notes payable to banks	-	24,000
Accounts payable	46,858	58,783
Accrued taxes	33,766	32,183
Customers' deposits	16,975	16,399
Amounts due customers	17,202	14,896
Accrued wages and benefits	27,450	22,711
Other	30,408	29,564
Total current liabilities	188,768	214,608
Deferred Credits and Other Liabilities
Other	6,580	7,410
Total deferred credits and other liabilities	6,580	7,410
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,      31,303,977 shares outstanding at March 31, 2002, and      31,248,547 shares outstanding at December 31, 2001	313	312
Premium on capital stock	237,279	235,976
Capital surplus	2,802	2,802
Retained earnings	264,080	230,554
Accumulated other comprehensive income, net of tax	1,540	7,168
Deferred compensation on restricted stock	(1,325)	(1,513)
Deferred compensation plan	7,941	7,222
Treasury stock, at cost (301,605 shares at March 31, 2002,     and 341,465 shares at December 31, 2001)	(7,941)	(8,316)
Total common shareholders' equity	504,689	474,205
Long-term debt	542,916	544,133
Total capitalization	1,047,605	1,018,338
TOTAL CAPITAL AND LIABILITIES	$   1,242,953	$   1,240,356

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Three months ended March 31,(in thousands)	2002	2001
Operating Activities
Net income	$    38,990	$    46,992
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization	24,849	20,551
Deferred income taxes	1,532	(1,192)
Deferred investment tax credits	(112)	(112)
Change in derivative fair value	(1,315)	(2,269)
Loss (gain) on sale of assets	422	(61)
Net change in:
Accounts receivable	(12,560)	4,598
Inventories	32,354	(13,864)
Deferred gas costs	8,300	19,215
Accounts payable	(22,947)	(5,202)
Amounts due customers	(4,739)	(37,441)
Other current assets and liabilities	7,920	21,118
Other, net	(483)	497
Net cash provided by operating activities	72,211	52,830
Investing Activities
Additions to property, plant and equipment	(35,665)	(69,315)
Proceeds from sale of assets	140	63
Other, net	(152)	(227)
Net cash used in investing activities	(35,677)	(69,479)
Financing Activities
Payment of dividends on common stock	(5,466)	(5,223)
Issuance of common stock	2,400	4,048
Reduction of long-term debt	(1,193)	(1,262)
Net change in short-term debt	(23,963)	14,000
Net cash provided by (used in) financing activities	(28,222)	11,563
Net change in cash and cash equivalents	8,312	(5,086)
Cash and cash equivalents at beginning of period	6,482	11,594
Cash and Cash Equivalents at End of Period	$    14,794	$     6,508

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

STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
Three months ended March 31,(in thousands)	2002	2001

Operating Revenues	$ 196,524	$ 270,286
Operating Expenses
Cost of gas	96,442	174,736
Operations and maintenance	26,573	26,648
Depreciation	8,230	7,647
Income taxes
Current	18,391	14,651
Deferred, net	377	158
Deferred investment tax credits, net	(112)	(112)
Taxes, other than income taxes	12,468	16,382
Total operating expenses	162,369	240,110
Operating Income	34,155	30,176
Other Income (Expense)
Allowance for funds used during construction	213	492
Other, net	(137)	(266)
Total other income	76	226
Interest Charges
Interest on long-term debt	3,327	2,067
Other interest expense	362	1,002
Total interest charges	3,689	3,069
Net Income	$ 30,542	$ 27,333

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

BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	March 31, 2002	December 31, 2001
ASSETS
Property, Plant and Equipment
Utility plant	$   781,895	$   769,259
Less accumulated depreciation	391,575	384,430
Utility plant, net	390,320	384,829
Other property, net	191	308
Current Assets
Cash and cash equivalents	14,034	3,372
Accounts receivable
Gas	74,479	59,504
Merchandise	1,120	1,506
Other	1,151	626
Affiliated companies	23,690	-
Allowance for doubtful accounts	(11,100)	(11,100)
Inventories, at average cost
Storage gas inventory	18,963	50,978
Materials and supplies	5,501	5,363
Liquified natural gas in storage	2,854	3,146
Amounts due from customers	7,045	-
Deferred gas costs	9,476	17,776
Deferred income taxes	23,382	22,820
Prepayments and other	4,164	1,378
Total current assets	174,759	155,369
Deferred Charges and Other Assets	14,309	8,715
TOTAL ASSETS	$   579,579	$   549,221

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

BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands, except share data)	March 31, 2002	December 31, 2001
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         March 31, 2002, and December 31, 2001	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	202,688	172,147
Total common shareholder's equity	237,192	206,651
Long-term debt	184,879	185,000
Total capitalization	422,071	391,651
Current Liabilities
Long-term debt due within one year	5,000	5,000
Notes payable to banks	-	19,000
Accounts payable	34,636	37,077
Accrued taxes	41,308	29,505
Customers' deposits	16,975	16,399
Amounts due customers	17,202	14,896
Accrued wages and benefits	13,386	10,509
Other	10,294	7,289
Total current liabilities	138,801	139,675
Deferred Credits and Other Liabilities
Deferred income taxes	16,540	15,531
Accumulated deferred investment tax credits	1,092	1,204
Customer advances for construction and other	1,075	1,160
Total deferred credits and other liabilities	18,707	17,895
Commitments and Contingencies
TOTAL CAPITAL AND LIABILITIES	$   579,579	$   549,221

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

STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Three months ended March 31,(in thousands)	2002	2001
Operating Activities
Net income	$     30,542	$     27,333
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization	8,230	7,647
Deferred income taxes, net	377	158
Deferred investment tax credits	(112)	(112)
Net change in:
Accounts receivable	(15,114)	(5,234)
Inventories	32,169	(12,773)
Deferred gas costs	8,300	19,215
Accounts payable	10	(26,495)
Amounts due customers	(4,739)	(37,441)
Other current assets and liabilities	15,451	15,475
Other, net	(5,799)	(297)
Net cash provided by (used in) operating activities	69,315	(12,524)
Investing Activities
Additions to property, plant and equipment	(13,574)	(13,677)
Other, net	183	111
Net cash used in investing activities	(13,391)	(13,566)
Financing Activities
Dividends	-	(5,221)
Net advances from (to) affiliates	(26,141)	12,063
Reduction of long-term debt	(121)	-
Net change in short-term debt	(19,000)	14,000
Net cash provided by (used in) financing activities	(45,262)	20,842
Net change in cash and cash equivalents	10,662	(5,248)
Cash and cash equivalents at beginning of period	3,372	9,113
Cash and Cash Equivalents at End of Period	$   14,034	$     3,865

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. Certain reclassifications were made to conform prior years' financial statements to the current-quarter presentation.

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. 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 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. 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 m ay be expected for the year.

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 util ity'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 fromforce majeure events such as storms, severe weather, and outages, when one or a combination of two such events result 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 Mar ch 31, 2002, and December 31, 2001, the ESR balance of $2.8 million and $2.7 million, respectively, 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 b e 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 cash flow 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, collars 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. Energen's net income in the three-month period ended March 31, 2002, reflected a non-cash benefit of $2.2 million, net of tax. Net income in the year ended December 31, 2002, will reflect a total non-cash benefit of $5.9 million, net of tax, related to Enron's hedge position.

As of March 31, 2002, $3.1 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, including $3.7 million of gains, net of tax, 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 $168,000 for the three-months ended March 31, 2002, 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 $802,000 for the quarter on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of March 31, 2002, the Company ha d 0.6 billion cubic feet (Bcf) of gas basis hedges, 9.1 Bcf of gas collars and swaps and 0.9 million barrels (MMBbl) of oil basis hedges that did not meet the definition of a cash flow hedge, however, the Company considers these hedges to be viable economic hedges. As of March 31, 2002, and December 31, 2001, the Company had $2.3 million and $5.9 million, respectively, included in deferred income taxes on the consolidated balance sheets related to other comprehensive income.

As of March 31, 2002, 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, 19.5 Bcf of gas production at an average NYMEX price of $3.36 per Mcf, 0.4 Bcf of gas production hedged at a NYMEX collar price of $4.25 to $6.15 per Mcf, 3.6 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.25 per Mcf, 3.6 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.30 per Mcf and 2.1 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.62 per Mcf. Energen Resources also had hedges in place for 1,095 thousand barrels (MBbl) of its estimated oil production at an average NYMEX price of $25.08 per barrel. In addition, the Company had hedged the basis difference on 0.6 Bcf of its estimated 2002 gas production and 0.9 MMBbl of its estimated 2002 oil production. Realized prices are anticipated to be lower than NYMEX prices due to basis differences and other factors. Pro duction estimates for 2002 total 76 Bcfe, including 46.5 Bcf of gas, 3.2 MMBbl of oil and 1.7 MMBbl of natural gas liquids.

As of March 31, 2002, 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. Subsequent to March 31, 2002, Energen Resources entered into additional swaps for 2003, resulting in a total of 5.3 Bcf of its gas production hedged at an average NYMEX price of $4.07. In addition, the Company hedged the basis difference on 4.8 Bcf of its estimated 2003 gas production. 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 ef fective 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 March 31, 2002, and December 31, 2001, Alagasco had recorded an $8.4 million asset and a $378,000 asset, 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. RECONCILIATION OF EARNINGS PER SHARE

		Three months ended				Three months ended
(in thousands, except per share amounts)		March 31, 2002				March 31, 2001
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount
Basic EPS	$  38,990		31,180	$  1.25	$  46,992		30,662	$  1.53
Effect of Dilutive Securities
Long-range performance shares			105				103
Stock options			134				224
Restricted stock			2				8
Diluted EPS	$   38,990		31,421	$  1.24	$  46,992		30,997	$  1.52

For the three months ended March 31, 2002, the Company had certain options and restricted stock that were excluded from the computation of diluted EPS, as their effect was anti-dilutive.

5. 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
	March 31,
(in thousands)	2002	2001
Operating revenues
Oil and gas operations	$ 47,859	$ 63,194
Natural gas distribution	196,524	270,286
Total	$ 244,383	$ 333,480
Operating income (loss)
Oil and gas operations	$ 8,430	$ 24,210
Natural gas distribution	52,811	44,873
Eliminations and corporate expenses	(457)	(363)
Total	$ 60,784	$ 68,720

(in thousands)	March 31, 2002	December 31, 2001
Identifiable assets
Oil and gas operations	$685,459	$ 687,776
Natural gas distribution	555,889	549,221
Eliminations and other	1,605	3,359
Total	$1,242,953	$ 1,240,356

6. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended	Three months ended
(in thousands)	March 31, 2002	March 31, 2001
Net Income	$   38,990	$   46,992
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($1.8) million and $9.7 million	(2,871)	15,231
Reclassification adjustment, net of tax of ($1.8) million and $15.4 million	(2,757)	24,028
Comprehensive Income	$  33,362	$   86,251

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

(in thousands)	March 31, 2002	December 31, 2001
Unrealized gain on hedges, net of tax of $2.3 million and $5.9 million	$ 3,634	$ 9,262
Minimum pension liability, net of tax of ($1.1) million	(2,094)	(2,094)
Accumulated Other Comprehensive Income	$ 1,540	$ 7,168

7. 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.

8. ACQUISITION OF FIRST PERMIAN, L.L.C. 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 Company estimates the total acquisition will approximate $182 million; this reflects an effective date of January 1, 2002, with appropriate purchase price adjustments from that date forward until completion of the transaction resulting from interim cash flows and related tax items.

Energen Resources acquired an estimated 43 million barrels of oil equivalent reserves. More than 95 percent of the acquisition reserves are oil, and approximately 60 percent are proved developed producing, with the remainder representing behind-pipe and proved undeveloped reserves as well as a small percentage of probable and possible reserves. With the addition of planned development expenditures of approximately $100 million, the all-in reserve cost of this acquisition approximates $6.55 per barrel of oil equivalent, or $1.09 per Mcf equivalent.

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

RESULTS OF OPERATIONS

Energen's net income totaled $39 million ($1.24 per diluted share) for the three months ended March 31, 2002, compared to net income of $47 million ($1.52 per diluted share) recorded in the same period last year. Energen Resources Corporation, Energen's oil and gas subsidiary, realized net income of $8.7 million in the current quarter as compared with $19.8 million in the same quarter last year primarily as a result of significantly lower sales prices for oil, natural gas and natural gas liquids slightly offset by a non-cash benefit of $2.2 million after-tax, or $0.07 per diluted share, associated with its previous hedge position with Enron North America Corp. (Enron). Energen's natural gas utility, Alagasco, reported net income of $30.5 million in the first quarter as compared to $27.3 million in the same period last year primarily due to the utility earning on a higher level of equity and to the timing of revenue recovery between quarters.

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, was 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 24.3 percent to $47.9 million for the three months ended March 31, 2002, largely as a result of lower commodity prices. Including the non-cash benefit from the former Enron hedges, realized gas prices fell 29.4 percent to $2.66 per Mcf, while realized oil prices decreased 2.6 percent to $22.40 per barrel in the current quarter. Natural gas liquids prices decreased 52.4 percent to an average price of $10.20 per barrel.

Natural gas production in the first quarter increased slightly to 11.7 Bcf, while oil volumes rose 11.6 percent to 547 MBbl. Natural gas liquids production increased 35.5 percent to 401 MBbl. Natural gas comprised 67 percent of Energen Resources' production for the current quarter.

Energen Resources enters into cash flow 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, collars 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.

Energen Resources had certain swap agreements with Enron as the counterparty as of October 1, 2001, as more fully discussed in Note 3. These swap agreements ceased to qualify as cash flow hedges during October 2001 as a result of Enron's credit issues. As of March 31, 2002, 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, 19.5 Bcf of gas production at an average NYMEX price of $3.36 per Mcf, 0.4 Bcf of gas production hedged at a NYMEX collar price of $4.25 to $6.15 per Mcf, 3.6 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.25 per Mcf, 3.6 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.30 per Mcf and 2.1 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.62 per Mcf. Energen Resources also had hedges in place for 1,095 thousand barrels (MBbl) of its estimated oil production for 2002 at an average NYMEX price of $25.08 per barrel. In a ddition, the Company had hedged the basis difference on 0.6 Bcf of its estimated 2002 gas production and 0.9 MMBbl of its estimated 2002 oil production. Realized prices are anticipated to be lower than NYMEX prices due to basis differences and other factors. Production estimates for 2002 total 76 Bcfe, including 46.5 Bcf of gas, 3.2 MMBbl of oil and 1.7 MMBbl of natural gas liquids.

As of March 31, 2002, 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. Subsequent to March 31, 2002, Energen Resources entered into additional swaps for 2003, resulting in a total of 5.3 Bcf of its gas production hedged at an average NYMEX price of $4.07. In addition, the Company hedged the basis difference on 4.8 Bcf of its estimated 2003 gas production. 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. There were no material sales of property reported by Energen Resources in the current quarter or the prior year quarter.

Operations and maintenance (O&M) expense remained stable for the quarter. Lease operating expenses decreased by $1.3 million for the quarter while exploration expense was higher by $1.5 million than the same period in the prior year.

Energen Resources' depreciation, depletion and amortization (DD&A) expense for the quarter rose $3.7 million primarily driven by market declines in commodity prices. The average depletion rate for the current quarter was $0.93 as compared to $0.78 for the same period last year.

Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $3.6 million lower this quarter primarily as a result of the significantly decreased commodity market prices.

Natural Gas Distribution

Natural gas distribution revenues decreased $73.8 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 11.4 percent warmer than in the same period last year contributed to a 15.3 percent decrease in residential sales volumes and a 17.7 percent decrease in small commercial and industrial customer sales volumes. Transportation volumes increased 15.2 percent primarily due to reduced consumption resulting from higher gas prices and a general economic weakness in the same period last year. Significantly lower commodity gas prices along with decreased gas purchase volumes contributed to a 44.8 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 ba sis to substantially remove the effect of departures 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 remained stable in the first quarter primarily due to reduced bad debt expense offset by increased labor related and insurance costs. A 7.6 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 remained stable for the quarter. Influencing interest expense was the issuance of $40 million of 6.25% Notes and $35 million of 6.75% Notes in August 2001 by Alagasco, largely offset by Energen's retirement of 8% Debentures for $18.3 million in April 2001 and repayment of the majority of the borrowings under the Company's short-term credit facilities.

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 offset by lower nonconventional fuels tax credits of $1 million. The decrease in nonconventional fuels tax credits reflected the timing of the recognition on an interim basis. The estimated effective tax rate utilized in computing income tax expense reflects an expected financial recognition of $13.8 million of nonconventional fuels tax credits for 2002.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the current quarter were $72.2 million compared to $52.8 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. Working capital needs at Alagasco were affected by warmer-than-normal weather and decreased gas costs compared to the prior quarter.

The Company had a net investment of $35.7 million through the three months ended March 31, 2002, primarily in additions of property, plant and equipment. Energen Resources invested $21.7 million in capital expenditures primarily related to the development of oil and gas properties. Utility capital expenditures totaled $13.8 million in the quarter and primarily represented system distribution expansion and support facilities.

The Company used $28.2 million for financing activities in the first quarter primarily due to reduced borrowings under Energen's short-term credit facilities.

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 $267 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.

In 2002, Energen Resources plans to invest approximately $280 million in capital expenditures, including $182 million for the acquisition of First Permian L.L.C, (First Permian) acquired April 8, 2002, as more fully described in Note 8, and $90 million in development well drilling and related exploitation activities. Energen Resources' exploratory exposure in 2002 is estimated to be $5 million. Capital investment at Energen Resources in 2003 is expected to approximate $77 million for development well drilling and other exploitation activities and $5 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 be $900 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 also will provide up t o $14 million a year from the issuance of common stock through the dividend reinvestment and direct stock purchase plan, in addition to 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 which may reduce or eliminate the amount of additional financing described above.

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 $31 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 may issue 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 March 31, (in thousands, except sales price data)	2002		2001
Oil and Gas Operations
Operating revenues
Natural gas	$ 31,209		$ 43,233
Oil	12,248		11,264
Natural gas liquids	4,093		6,329
Other	309		2,368
Total	$ 47,859		$ 63,194
Sales Volumes
Natural gas (MMcf)	11,730		11,466
Oil (MBbl)	547		490
Natural gas liquids (MBbl)	401		296
Average sales price
Natural gas (Mcf)	$ 2.66		$ 3.77
Oil (barrel)	$ 22.40		$ 23.00
Natural gas liquids (barrel)	$ 10.20		$ 21.42
Other data
Depreciation, depletion and amortization	$ 16,619		$ 12,904
Capital expenditures	$ 21,658		$ 55,714
Exploration expenditures	$ 1,668		$ 179
Operating income	$ 8,430		$ 24,210
Natural Gas Distribution
Operating revenues
Residential		$ 137,411	$ 189,457
Commercial and industrial - small		47,397	70,500
Transportation		10,642	9,213
Other		1,074	1,116
Total		$ 196,524	$ 270,286
Gas delivery volumes (MMcf)
Residential		14,294	16,875
Commercial and industrial - small		5,493	6,676
Transportation		15,051	13,061
Total		34,838	36,612
Other data
Depreciation		$ 8,230	$ 7,647
Capital expenditures		$ 13,786	$ 14,115
Operating income		$ 52,811	$ 44,873

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 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 cash flow 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, collars 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. Energen's net income in the three-month period ended March 31, 2002, reflected a non-cash benefit of $2.2 million, net of tax. Net income in the year ended December 31, 2002, will reflect a total non-cash benefit of $5.9 million, net of tax, related to Enron's hedge position.

As of March 31, 2002, $3.1 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income, including $3.7 million of gains, net of tax, 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 $168,000 for the three-months ended March 31, 2002, 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 $802,000 for the quarter on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of March 31, 2002, the Company ha d 0.6 billion cubic feet (Bcf) of gas basis hedges, 9.1 Bcf of gas collars and swaps and 0.9 million barrels (MMBbl) of oil basis hedges that did not meet the definition of a cash flow hedge, however, the Company considers these hedges to be viable economic hedges. As of March 31, 2002, and December 31, 2001, the Company had $2.3 million and $5.9 million, respectively, included in deferred income taxes on the consolidated balance sheets related to other comprehensive income.

As of March 31, 2002, 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, 19.5 Bcf of gas production at an average NYMEX price of $3.36 per Mcf, 0.4 Bcf of gas production hedged at a NYMEX collar price of $4.25 to $6.15 per Mcf, 3.6 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.25 per Mcf, 3.6 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.30 per Mcf and 2.1 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.62 per Mcf. Energen Resources also had hedges in place for 1,095 thousand barrels (MBbl) of its estimated oil production at an average NYMEX price of $25.08 per barrel. In addition, the Company had hedged the basis difference on 0.6 Bcf of its estimated 2002 gas production and 0.9 MMBbl of its estimated 2002 oil production. Realized prices are anticipated to be lower than NYMEX prices due to basis difference and other factors. Prod uction estimates for 2002 total 76 Bcfe, including 46.5 Bcf of gas, 3.2 MMBbl of oil and 1.7 MMBbl of natural gas liquids.

As of March 31, 2002, 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. Subsequent to March 31, 2002, Energen Resources entered into additional swaps for 2003, resulting in a total of 5.3 Bcf of its gas production hedged at an average NYMEX price of $4.07. In addition, the Company hedged the basis difference on 4.8 Bcf of its estimated 2003 gas production. 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 ef fective 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 March 31, 2002, and December 31, 2001, Alagasco had recorded an $8.4 million asset and a $378,000 asset, 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

Information with respect to the annual meeting of shareholders held on January 30, 2002, is reported in Item 4 of Energen Corporation 10-Q for the three months ended December 31, 2001.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a. Exhibits

None

b. Reports on Form 8-K

Form 8-K dated March 14, 2002, reporting that Energen Resources signed a Purchase and Sale Agreement with First Permian, L.L.C.

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
May 14, 2002	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
May 14, 2002	By   /s/ G. C. Ketcham
	G. C. Ketcham
	Executive Vice President, Chief
	Financial Officer and Treasurer of
	Energen Corporation and Alabama Gas
	Corporation
May 14, 2002	By   /s/ Grace B. Carr
	Grace B. Carr
	Vice President and Controller of Energen
	Corporation
May 14, 2002	By   /s/ Paula H. Rushing
	Paula H. Rushing
	Vice President-Finance of Alabama Gas
	Corporation

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